Amendments to Gas Valuation Regulations for Indian Leases

SUMMARY: The Minerals Management Service (MMS) is proposing to amend

its regulations governing the valuation for royalty purposes of natural

gas produced from Indian leases. These changes would add alternative

valuation methods to the existing regulations. The proposed rule

represents recommendations of the MMS Indian Gas Valuation Negotiated

Rulemaking Committee (Committee). This proposed rule also contains two

new MMS forms and solicits comments on these information collections.

DATES: Comments must be submitted on or before November 22, 1996.

ADDRESSES: Mail written comments, suggestions, or objections regarding

the proposed rule to: Minerals Management Service, Royalty Management

Program, Rules and Procedures Staff, P.O. Box 25165, MS 3101, Denver,

Colorado, 80225-0165, courier address is: Building 85, Denver Federal

Center, Denver, Colorado 80225, or e:Mail David__G[email protected]. 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, e:Mail

David__G[email protected], 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 Donald T. Sant, Connie Bartram, and Greg Smith of the MMS, and

Peter Schaumberg of the Office of the Solicitor. Members of the MMS

Indian Gas Valuation Negotiated Rulemaking Committee also participated

in the preparation of this proposed rule.

I. Introduction

On August 4, 1994, MMS published an Advance Notice of Proposed

Rulemaking regarding the possible amendment of the valuation

regulations for gas production from Indian leases (59 FR 39712). The

stated intent of any amendments was to ensure that Indian mineral

lessors received the maximum revenues from mineral resources on their

land consistent with the Secretary of the Interior's (Secretary) trust

responsibility and lease terms. It was also MMS's desire to improve the

regulatory framework so that information was available which would

permit lessees to comply with the regulatory requirements at the time

that royalties were due.

On January 31, 1995, the Secretary chartered the Committee to

develop specific recommendations with respect to the valuation of gas

production from Indian leases (60 FR 7152, February 7, 1995). Members

of the Committee included representatives of the Navajo Nation, the

Jicarilla Apache Tribe, the Native American Rights Fund, the Shoshone

and Arapaho Tribes of the Wind River Reservation, the Northern Ute

Tribe, the Southern Ute Indian Tribe, the Ute Mountain Ute Tribe, the

Council of Energy Resource Tribes, the Shii Shi Keyah Association, the

Council of Petroleum Accountants Societies (COPAS), the Rocky Mountain

Oil and Gas Association (RMOGA), the Independent Petroleum Association

of Mountain States (IPAMS), a major producer, the Mid-continent Oil &

Gas Association, the Bureau of Indian Affairs, and MMS.

There were 19 members on the Committee. The Committee agreed that a

minimum of 14 people had to be in attendance to conduct the business of

the Committee. The Committee also agreed that it was necessary to have

a 2/3 vote of the members present in favor of a proposal to adopt the

proposal as a Committee recommendation.

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 Committee sessions were announced in the

Federal Register, were open to the public, and provided an opportunity

for public input. In addition, any interested persons may submit

written comments, suggestions, or objections regarding this proposed

rule to the location identified in the ADDRESSES section of this

preamble. As an aid to public participation in this rulemaking,

comments received will be posted on the internet at http://

www.rmp.mms.gov unless the submitter has requested confidentiality.

MMS commends the Committee's ability to compromise and develop a

proposal that would simplify royalty payments on natural gas produced

from Indian leases, provide lessees with the information to comply with

the regulations at the time royalties are due, decrease administrative

costs, decrease litigation costs, and provide the Indian lessors with

the maximum revenue consistent with their lease terms.

II. General Description of the Proposed Rule

In August 1996, the Committee published its final report which

summarizes the Committee's recommendations. This report forms the basis

for many of the proposals in this rulemaking and is an essential part

of the regulatory history for this proposed rulemaking. Contact the

person listed in FOR FURTHER INFORMATION CONTACT section or use the

Internet access (http://www.rmp.mms.gov) to obtain a copy of the

report.

The proposed rulemaking would simplify and add certainty to the

valuation of production from Indian leases. It provides a methodology

to calculate the value of production for standard form Tribal and

allottee Indian leases that provide for value to be based on factors

including the highest price paid or offered for a major portion of gas

(major portion) at the time royalty payments are due. Most valuation

would be based on published index prices for gas production from leases

on reservations. It would also provide an alternative methodology for

dual accounting. Thus, the lessee could elect to simplify the

calculations for the requirement to pay royalties on the greater of the

combined value of the residue gas and gas plant products resulting from

processing the gas, or the value of the gas prior to processing.

This proposed rule would eliminate the need to calculate specific

transportation allowances in most cases. Also, processing allowance

calculations for lessees choosing the alternative methodology for dual

accounting would be eliminated.

The requirement to file transportation or processing allowance

forms in anticipation of claiming an allowance would be eliminated. In

cases where lessees still would claim an allowance, data to verify the

allowance claimed would be submitted to MMS.

These proposed rules contain two new MMS forms: Form MMS-4410,

Certification for Accounting for Comparison, and Form MMS-4411, Safety

Net Report. These forms are attached to this notice of proposed

rulemaking as appendix A and appendix B. Commenters are requested to

provide comments on these forms according to the information under the

``Paperwork Reduction Act'' in part IV. Procedural Matters of this

notice.

[[Page 49895]]

A description of the major regulatory changes proposed in this

rulemaking is provided in the next section. MMS recently restructured

30 CFR part 206 to create separate subparts applicable only to Indian

leases (61 FR 5448, February 12, 1996). This was necessary because MMS

made changes to the valuation regulations applicable to Federal leases

that do not apply to Indian leases. This proposed rule also

restructures 30 CFR part 202 to have separate sections for Federal and

Indian leases. Thus, all the Indian valuation rules and procedures

would be contained in a new subpart J of 30 CFR part 202 and subpart E

in 30 CFR part 206.

In situations where the new index-based or other alternative

valuation methods would be inapplicable, MMS would retain much of the

structure of the existing valuation rules in 30 CFR part 206. A few

changes would be substantive. However, in an effort to clarify and

simplify those rules, MMS would be incorporating many changes to those

sections that are not substantive but are an effort to implement

concepts of plain English.

Also, on July 31, 1996, (62 FR 39931) MMS published a proposed

rulemaking to amend the transportation allowance regulations for

Federal and Indian leases. That proposed rule would clarify which costs

are deductible as transportation costs and which costs are not

deductible because they are not costs of transportation. MMS will

incorporate in this rule any changes as a result of that proposed

rulemaking.

III. Description of the Regulatory Proposal

30 CFR Part 202

MMS proposes to amend part 202 to add a new subpart J as described

below. Where necessary, MMS will change the references to the

applicable subparts of 30 CFR part 206 as they pertain to Indian gas,

and will rename subpart D in part 202 as Federal Gas.

Section 202.550 How to Determine the Royalty Due on Gas Production

MMS is adding paragraph names to highlight the information contents

of proposed Sec. 202.550. In paragraph (a), MMS proposes that a Tribe

rather than MMS would decide when the lessor would take Indian gas

royalty in-kind. This paragraph also contains a new provision stating

that a lessee of an Indian lease who demonstrates economic hardship may

request a royalty rate reduction which is subject to the approval of

the Indian lessor and the Secretary. MMS specifically would like

comment on whether the Department should provide approval for allotted

leases rather than seeking approval of the many individual allottees

who may share in a single lease.

Proposed Sec. 202.550(b) would require that you pay royalties on

your entitled share of gas production from Indian leases not in

approved Federal agreements, a defined term. It provides that you may

pay on your takes if you notify the Associate Director for Royalty

Management in writing that all persons paying royalties on the lease

also agree to pay on their takes. However, if you pay royalties on your

takes that are less than your entitled share, you are still liable for

the royalties on your entitled share if the person taking the

production does not pay the royalties that are owed. For example,

assume there are two lessees each owning 50 percent of an Indian lease,

and the production for a month is 100 Mcf. If lessee A takes 25 Mcf,

and lessee B takes 75 Mcf, lessee A pays royalties on 25 Mcf, but is

still liable for royalties on 50 Mcf if for some reason lessee B does

not pay royalties on the 75 Mcf it took.

In proposed Sec. 202.550(c), MMS has organized the regulation into

paragraphs (i) Royalty rate; (ii) Volume; and (iii) Value, to clarify

the way gas produced within an approved Federal agreement (AFA--

including units and communitization agreements) must be calculated,

reported, and paid to MMS or the Tribe.

In proposed Sec. 202.550(c), MMS proposes to retain the requirement

that royalty is due on the full monthly share of production allocated

to an Indian lease under the terms of the AFA at the royalty rate

specified in the lease. However, MMS is adding clarification that

royalty would be due on each lessee's (generally operating rights

owner's) entitled share of production allocable to the lease.

If a lessee takes its entitled share of production, value would be

determined under 30 CFR part 206 for the full volume. However, a lessee

may take more or less than its entitled share in a month. MMS proposes

that the value for royalty purposes of the entitled share of production

when the lessee (operating rights owner) takes more than its entitled

share of the AFA production would be the weighted average value of the

production taken. The existing regulations require lessees to

distribute ratably from the overtaken leases to the undertaken leases

using the value of the overtaken volumes. The proposed weighted average

value would ease the valuation work for lessees, MMS, and Indian

lessors.

Also included in Sec. 202.550(c) would be procedures to value the

portion of any production which a lessee is entitled to but does not

take. If a lessee takes a portion of its entitled volumes, the value of

production would be the weighted average value of the production that

lessee took for the lease in the AFA. If a lessee takes none of its

entitled volume, the value of production would be the index- based

value (discussed later in this preamble) for leases in a zone with a

valid index (discussed at 30 CFR 206.172). In a zone without a valid

index, the value of production would be the first applicable of several

benchmarks. The first benchmark under 30 CFR part 206 would be the

weighted- average value of the gas that the lessee took from other

leases in the same AFA that month. The second benchmark under 30 CFR

part 206 would be the weighted-average value of production the lessee

took from other Indian leases in the same field or area that month. The

third benchmark under 30 CFR part 206 would be the weighted-average

value of production the lessee took from Indian leases in the same AFA

the previous month. The fourth benchmark under 30 CFR part 206 would be

the weighted-average value of production the lessee took from Indian

leases in the same field or area the previous month. The fifth and last

benchmark would be the latest major portion value MMS sent to the

lessee (discussed at 30 CFR 206.174).

Section 202.551 Standards for Reporting and Paying Royalties on Gas

This section is basically unchanged from the current regulations at

Sec. 202.152.

30 CFR Part 206

MMS is proposing to amend subpart E applicable only to Indian gas

valuation. Many of the provisions are the same as in the existing rules

in substance, but would be rewritten for purposes of clarity.

Section 206.170 What This Subpart Applies To

This section would be renamed and is basically the same as the

existing rules. A new paragraph (c) would be added to allow valuation

methodologies other than those prescribed in the rules if the lessee,

Tribal lessor, and MMS jointly agree to the methodology. For Indian

allottee leases, only MMS and the lessee must agree.

Section 206.171 Definitions

MMS would retain most of the definitions in Sec. 206.171. However,

new definitions would be added and existing

[[Page 49896]]

definitions revised to allow for the simplification of valuation

methodologies. New definitions are proposed for: active spot market,

approved Federal agreement, dedicated, drip condensate, dual

accounting, entitlement, facility measurement point, index, index

pricing point, index zone, major portion, MMS, natural gas liquids,

operating rights owner, takes, and zone. These definitions will be

discussed below where they appear in the text of the regulation.

The proposed rule would remove the definitions of marketing

affiliate and warranty contract because they are no longer relevant to

valuation in today's market. The definition of allowance would be

revised to reflect the elimination of certain forms the existing

regulations require.

Section 206.172 How To Value Gas Produced from Leases in an Index Zone

This section is proposed to be removed, and a new Sec. 206.172 is

proposed to be added. This section is the principal new provision of

the proposed regulation. This proposal removes the existing text of

Sec. 206.172 and replaces it with new language explaining the new

valuation principles in the rule. Where it is applicable, it would

greatly simplify the gas valuation process. This section would

determine the value of gas production using data available in national

publications. Likewise, major portion calculations could be made from

the information published monthly in various publications. It

simplifies what has been a difficult royalty valuation calculation for

MMS and one that lessees seldom could make. This new calculation also

would provide increased revenue for Indian Tribes and allottees

consistent with their lease terms.

This proposed Sec. 206.172 establishes the rules for lessees to use

an index-based valuation method to value gas production from leases in

MMS-determined index zones. These index zones, defined in proposed

Sec. 206.171 as a geographic area containing blocks or fields that MMS

will define, would reflect areas with active spot markets. An active

spot market is defined in proposed Sec. 206.171 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 index zone. An index pricing point

is defined in proposed Sec. 206.171 as any point on a pipeline for

which there is an index. An index zone could be a large area or a small

area. For Jicarilla-Apache Reservation, Southern Ute Reservation and

Navajo Nation Indian leases, one likely index zone would be the San

Juan basin. This is because the publications who publish the index

prices generally publish one index price for this entire area. Another

likely index zone would be the Rocky Mountain zone, which would apply

to the Uintah and Ouray Reservation and the Wind River Reservation.

Proposed paragraph (a) would provide that this index-based method

applies to leases with a major portion provision, a defined term. In

these leases, the Secretary may determine value based upon the highest

price paid or offered for a major portion of gas production in the

field. It also would apply to leases which do not have a major portion

provision but provide for the Secretary to determine value. This

section also would provide that this index-based value could not be

used to value carbon dioxide, nitrogen, or other non-Btu components of

the gas stream.

Proposed paragraph (b) explains how to value residue gas and gas

prior to processing. This section also applies to gas that the lessee

certifies to MMS that it is not processed before it flows into a

pipeline with an index (i.e., a pipeline with published index prices)

but which may in fact be processed downstream of that point. It also

should be noted that this section applies to both arm's-length and non-

arm's-length sales.

Under proposed paragraph (b)(2), the value of gas which is not sold

under a dedicated contract (defined in 30 CFR 206.171), would be the

index-based value calculated as described below. However, if that gas

production was subject to a previous contract which was the subject of

a gas contract settlement, the lessee would be required to compare the

index-based value with the value determined under 30 CFR 206.174. That

section basically applies the valuation procedures that have been in

effect since 1988. Thus, for example, if the lessee's gross proceeds

are higher, that would determine value. This was not a Committee

recommendation, but is proposed by MMS to continue current policy. The

issue of royalty on contract settlement proceeds is currently in

litigation.

If the gas is sold under a dedicated contract, then the value is

the higher of the index-based value, described below, or the value

determined under 30 CFR 206.174.

This section of the proposed rule also makes the index-based method

available to value processed gas. Under paragraph (c), if gas is

processed before it flows into a pipeline with an index, value is the

higher of:

The index-based value, described below, or

The value of the gas after processing, including the

residue gas and all gas plant products.

The value of the gas after processing may be determined two ways.

The first is to use the alternative method for dual accounting

described below in Sec. 206.173 (which applies a specified increment to

the value of the unprocessed gas to reflect the increase in the value

for processing). The second method is to determine the combined value

of the residue gas (using either paragraph (b)(2) or (b)(3) of this

section, described above), the gas plant products (using the applicable

valuation procedures), and any drip condensate.

Paragraph (d) of proposed Sec. 206.172 describes how to calculate

the index-based value per MMBtu of production. This index-based value

must be calculated separately for each zone where a lessee has

production.

First, for each MMS-approved publication, the lessee must calculate

the average (a simple arithmetic average) of the highest reported

prices for all of the index pricing points in the index zone. This

includes all index pricing points included in the publication even if

the lessee does not sell any gas which flows through a particular index

pricing point. As explained below, MMS may exclude certain index prices

from the calculations. Next, these averages are summed and the total is

divided by the number of publications. This average is then reduced by

a factor of 10 percent, but not less than 10 cents or more than 30

cents per MMBtu. This reduction is intended to reflect an allowance for

transportation. Therefore, when using this index-based method, no other

transportation allowance will apply.

Proposed paragraph (d)(2) would provide that MMS will publish in

the Federal Register the index zones that are eligible for the index-

based valuation method. It also lists the criteria MMS will consider in

determining eligible index zones. The criteria include common markets

served and common pipeline systems. The published index prices within

an index zone, therefore, should be similar.

One of the criteria in determining zone eligibility would be that

MMS-approved publications establish index prices that accurately

reflect the value of production in the field or area where the

production occurs. This would allow MMS, in consultation with affected

Tribes and industry, to consider whether a particular set of index

prices properly reflect value near the production areas.

[[Page 49897]]

Proposed paragraph (d)(3) allows MMS to disqualify a zone if market

conditions change. Before a zone is disqualified, MMS will hold a

technical conference. MMS will publish any zone disqualifications in

the Federal Register.

Proposed paragraph (d)(4) would provide that MMS publish the MMS-

acceptable publications in the Federal Register. It also lists the

criteria MMS will consider in determining acceptable publications. The

criteria include that buyers and sellers frequently use the

publications. Also, the publications must use adequate survey

techniques, and they must be independent from MMS, lessors, and

lessees.

Proposed paragraph (d)(5) would provide that publications could

petition MMS to become an acceptable publication.

Proposed paragraph (d)(6) would allow MMS to exclude an individual

index price for an index zone in a publication that MMS otherwise

approves. This would allow exclusion of a particular index price that

MMS may find to be anomalous without disqualifying the other index

prices for other index zones in that publication.

Proposed paragraph (d)(7) would provide that MMS will specify which

tables in the publications to use to determine the index-based value.

Proposed paragraph (d)(8) states that transportation or processing

allowance deductions are not to be used if the index-based value is

used to value gas production. As explained above, the index-based value

has already been adjusted between 10 cents and 30 cents per MMBtu to

reflect transportation. As explained below, the dual accounting

provision of the rule would provide adjustments for processing gas.

To ensure that the index-based value represents market value, the

proposed rule provides for two safeguards. The first safeguard would be

situations where there are contracts that dedicate gas production from

specific wells or leases to those sales contracts. The Committee was

aware that certain sales contracts exist that are for higher prices

than available under the current spot market. Thus, as explained above,

under Sec. 206.172(b)(3), for dedicated contracts the lessee would have

to calculate its value under current principles (gross proceeds) in the

regulations, less allowances, and compare that value to the index-based

value. The lessee would pay royalties on the higher of the two values.

The Committee agreed that the Indian lessor should receive the benefit

from these higher price sales contracts. The Committee did not believe

that this provision added complexity because most dedicated gas sales

contracts were wellhead sales and all dedicated gas sales contracts

were for gas sales before the index point. Lessees, therefore, would

not have to trace gas sales beyond the index point.

The second safeguard is in proposed Sec. 206.172(e) that provides

for a minimum value for royalty purposes under this section, referred

to as the safety net price. The published index prices reflect prices

for gas sold in the spot market. The volume of gas being sold on the

spot market currently is between 25-40 percent of total production.

Therefore, to ensure that the index-based value represents the value of

all market transactions, the Committee proposed a safety net to compare

index prices to prices that reflect sales made beyond an index point.

The safety net price would be calculated using prices received for gas

sold downstream of the index point. It would include only the lessee's

or its affiliates sales prices, and it would not require detailed

calculations for the costs of transportation. This was a contentious

issue with the industry representatives, as they object to tracing gas

sales. They also believe that the index-based value is representative

of market value.

By June 30 following each calendar year, the lessee would be

required to calculate for each month of the calendar year a safety net

price. This must be calculated for each index zone where the lessee has

an Indian lease. The safety net price for each index zone would be the

volume weighted average contract price per delivered MMBtu of gas sold

under the lessee's arm's-length contracts for the disposition of gas

from all of the lessee's leases in the same index zone (in this

instance including the lessee's Federal, State and fee properties in

addition to its Indian leases). However, the lessee would only include

sales under those contracts that establish a delivery point beyond the

first index pricing point to which the gas flows. Moreover, those

contracts must include gas attributable to one or more of the lessee's

Indian leases in the index zone. The safety net price would capture the

significantly higher-values for sales occurring beyond the index point.

The lessee would submit its safety net price to MMS annually (by June

30) using Form MMS-4411. For purposes of this subsection only, the

contract price would not include any amounts the lessee received in

compromise or settlement of a predecessor contract for that gas. The

contract price also would not include any adjustments to that price for

placing gas production in marketable condition or to market the gas, or

for any amount related to marketable securities associated with the

sales contract (e.g., NYMEX futures). Also, except as described below,

no transportation allowance would be applicable.

The Committee recognizes that transportation adds value for sales

beyond the index point. To adjust for this value, the lessee would

reduce the safety net price by 20 percent before any comparison is made

to the index-based value. Use of a percentage was selected to retain

simplicity in these rules compared to requiring the calculation of the

actual cost of transportation. The Committee agreed that the 20 percent

figure was a reasonable approximation of transportation costs. This

reduction for transportation is greater than the 10 percent reduction

in Sec. 206.172(d)(1) because the safety net prices relate to sales

that occur further from the lease.

The amount that is 80 percent of the safety net price would be

compared to the amount that is 125 percent of the monthly index value

for the index zone. The use of 125 percent of the index value also

recognizes that there can be value added services other than

transportation after the index point. The lessee would owe additional

royalties plus late-payment interest if 125 percent of the index value

were less than 80 percent of the safety net price. To calculate the

additional royalties owed, the lessee would multiply the safety net

differential (the 80 percent figure minus the 125 percent figure) by

the volume of the lessee's gas production from Indian leases in the

index zone that is sold beyond the first index pricing point in the

index zone through which the gas flowed. This is the gas production

that was sold at the higher prices. The additional revenue would be

allocated to each Indian lease in the index zone with production sold

beyond the index pricing point. We call this safety net production. The

additional revenue would be allocated by dividing the volume (in

MMBtu's) of production from an Indian lease in the index zone by the

total volume (in MMBtu's) of safety net production from all of the

lessee's Indian leases and multiplied by the additional royalties owed.

The Committee believed that index-based value was a good determinant of

value for production sold before or at the index point, and any safety

net price ought to apply only to the production that was sold at the

higher prices.

The Committee had certainty as one of its goals. The proposed rule

would give MMS 1 year from the date it receives the lessee's Form MMS-

4411 providing the safety net price to order the lessee to amend its

safety net price

[[Page 49898]]

calculation. If MMS did not order any adjustment to the safety net

price, the safety net price would be final for the lessee.

Section 206.173 Alternative Methodology for Dual Accounting (Accounting

for Comparison)

This section would be removed and a new Sec. 206.173 is proposed

that would offer an option for lessees to meet the dual accounting

requirement in Indian leases, applicable to processed gas, using a

simple calculation. Dual accounting is required under most Indian

leases whenever gas is processed.

Under the proposed rule, a lessee would have the option to use the

traditional dual accounting method in proposed Sec. 206.176. This

method compares the value of the gas prior to processing to the value

of the residue gas, gas plant products, and drip condensate. Each of

these values would be determined using the various valuation provisions

of the rules, as appropriate. Royalty is due on the higher of the two

values.

However, the proposed rule in Sec. 206.173(b) also would provide

the simpler alternative methodology for dual accounting. Under this

method, the lessee first would determine the pre-processing value of

the gas production using either Sec. 206.172 or Sec. 206.174. Then, a

prescribed increment would be applied to reflect the increased value of

the production after processing. Thus, value would be determined using

the following equation:

Post-processing value = (Value determined in Sec. 206.172 or

Sec. 206.174) x (1 + Increase for Dual Accounting).

The proposed increments are specified in Sec. 206.173. They were

calculated using two different values for the processing allowance of

one test plant. A processing allowance of 33 percent was used to

represent a typical allowance for a lessee that does not own an

interest in the processing plant. A processing allowance of 20 percent

was used as a typical allowance for a lessee that has an ownership

interest in the processing plant. The increments represent the average

uplifts in the value of gas prior to processing over several years of

the value of gas after processing based on gas Btu quality and

allowance data for one plant.

The dual accounting increase in wellhead value therefore would be

based on two factors: The Btu quality at the facility measurement

point, and whether the lessee has an ownership interest in the

processing plant. The increments range from 2.75 percent to 35.5

percent. The Btu quality for any lease would be the weighted-average

Btu content of all the wells in the lease or agreement measured at the

facility measurement points.

Therefore, under this alternative methodology, if any of the gas

from the lease was processed and the weighted- average Btu quality per

cubic foot was greater than 1,000 Btu per cubic foot (Btu/cf), the

lessee simply could choose to increase the value for all the gas prior

to processing by the dual accounting increment and pay royalties on

that value. If the weighted-average Btu quality per cubic foot for a

month on a lease were less than 1,000 Btu/cf and some or all of the gas

were processed, the lessee would use the alternative methodology for

the volumes of lease production from wells whose quality exceeds 1,000

Btu/cf. For wells on the lease whose quality is equal to or less than

1,000 Btu/cf, dual accounting is not required. In this case, the lessee

would report the volumes and the weighted-average Btu quality for wells

above 1,000 Btu/cf as a separate item on Form MMS-2014, and report

another line item for the volume of gas and the weighted-average

quality for wells with Btu quality below 1,000 Btu/cf.

Under proposed Sec. 206.173(a), lessees would make an election

between actual dual accounting and the alternative methodology. The

election must be made separately for each MMS-designated area. The

election would apply to all the lessee's leases in that designated

area. It could happen that co-lessees of a lease would use different

dual accounting methods for their representative volumes because they

have made different elections for all their respective lease interests

in the designated area. Also, even if two co-lessees elected to use the

alternative methodology, the resulting valuation could be different if

one co-lessee owned an interest in the processing plant and therefore

was required to use a higher increment. The designated areas are

limited to:

Alabama-Coushatta

Blackfeet Reservation

Crow Reservation

Fort Belknap Reservation

Fort Berthold Reservation

Fort Peck Reservation

Jicarilla Apache Reservation

MMS-designated groups of counties in the State of Oklahoma

Navajo Reservation

Northern Cheyenne Reservation

Rocky Boys Reservation

Southern Ute Reservation

Turtle Mountain Reservation

Uintah and Ouray Reservation

Ute Mountain Ute Reservation

Wind River Reservation

Any other area that MMS designates.

MMS also will publish in the Federal Register a list of all Indian

leases that are in a designated area for purposes of these regulations.

A lessee could elect to begin using the alternative methodology at

the beginning of any month. Once made, the election would remain in

effect until the end of the following calendar year. Thereafter, the

election to use the alternative methodology must remain in effect for

two calendar years, unless the lessee receives permission to change

from MMS and, for Tribal leases, the Tribal lessor.

If any new wells come into production, or if the lessee acquires

new leases in the designated area, they too must be subject to the

election to use the alternative methodology.

Section 206.174 How To Value Gas Production When an Index- Based

Method Cannot Be Used

Section 206.174 would be removed, and a new Sec. 206.174 is

proposed. This new section would apply to the valuation of gas

production that:

Is from leases outside an index zone;

Is sold under dedicated contracts;

Is a gas plant product subject to the actual dual

accounting method where the actual processing costs are used for the

processing allowance; or

Is a non-Btu component of the gas stream.

This section would consolidate the valuation principles previously

included in existing Secs. 206.172 and 206.173 for the valuation of

processed and unprocessed gas primarily to eliminate redundant

provisions. These are the rules that have been in effect since 1988. It

would incorporate the gross proceeds valuation principles and combine

them into one section because there is no need to separate the

valuation of unprocessed gas from processed gas.

This section also provides that MMS would calculate a major portion

value from values lessees initially submitted to MMS using these gross

proceeds principles. To do this, lessees would report their current

production month's value based on the valuation methodology of the

current regulations depending upon whether it was an arm's-length or

non-arm's-length transaction. Thus, for gas sold under an arm's-length

contract, the lessee would report its gross proceeds less applicable

allowances. For gas sold under a non-arm's-length contract, the lessee

would report its value after following the benchmarks specified in the

rule at Sec. 206.174. Lessees would be required to report allowances as

separate items on

[[Page 49899]]

Form MMS-2014. The lessee would report the value as either processed

gas and associated natural gas liquids or unprocessed gas.

Within 90 days of the reporting month, MMS would calculate a major

portion value, described below, using lessees' reported values for

unprocessed gas and residue gas for leases on each designated area (the

same designated areas as under Sec. 206.173). MMS would send written

notice to each lessee of the major portion value applicable to its

leases depending upon where they are located.

The lessee would have 30 days to submit amended Forms MMS-2014 to

MMS if the major portion was higher than the lessee's previously

reported value. Lessees also would compute their dual accounting value

using the major portion value as the wellhead value per MMBtu. They

could make the dual accounting calculation using the alternative

methodology or the actual dual accounting method using the major

portion value as the value of the residue gas. However, late payment

interest on any underpayment associated with a higher major portion

value would not begin to accrue until the date the amended Form MMS-

2014 is due to MMS. The Committee did not consider it equitable to

assess interest for periods before MMS notifies the lessee of the major

portion value.

For each designated area, MMS would calculate the major portion

value by arraying all of the prices and volumes of the gas reported on

Form MMS-2014 for leases in the designated area. Prices would be

reduced first for any allowable transportation costs. The lowest price

would be at the bottom and the highest price at the top. The major

portion would be the value at which 25 percent of the gas was sold

starting down from the highest price paid. This would be a change from

the current regulation of calculating the major portion value as the

value at which 50 percent plus 1 Mcf of gas was sold starting from the

bottom.

The Committee had considerable deliberation on this issue. Indian

lessors have criticized MMS since the publication of the definition of

the major portion value in 1988. They have argued that the definition

of the major portion in the 1988 regulation does not adequately

represent the lease terms on the highest price paid or offered for a

major portion of production. They argue that median is not synonymous

with major. The Committee agreed that the price at which 25 percent or

more of the gas is sold is a reasonable compromise on the term major.

The Committee agreed that the major portion value at the 25th

percentile from the top was a reasonable safeguard for royalty payments

in non-index areas. Therefore, the Committee recommended that the MMS-

computed major portion value not be subject to unilateral change by MMS

once MMS issues a written notice, building certainty into the lessee's

royalty valuation. That provision is in Sec. 206.174(a)(4)(ii). A

lessee or an Indian lessor could appeal the major portion value if they

could demonstrate that MMS had not performed the calculation correctly.

The Committee discussed having a minimum value for gas plant

products when the alternative methodology for dual accounting is not

used to value the production and the lessee chooses to use the actual

dual accounting methodology. The Committee did not agree on this issue,

but voted to include in the proposed rule a minimum value based on some

concepts MMS used previously in a procedure paper on natural gas liquid

products valuation.

The proposal is included at Sec. 206.174(g)(2). It specifies that

for each gas plant product, the value cannot be less than the monthly

average minimum price reported in commercial price bulletins less a

specified estimate of the cost of transportation and fractionation. The

average minimum price for production from leases in Colorado in the San

Juan Basin, New Mexico, and Texas would be prices reported for gas

plant products at Mont Belvieu less 8.0 cents for transportation and

fractionation. The average minimum price for production from leases in

Arizona, in Colorado outside the San Juan Basin, Minnesota, Montana,

North Dakota, Oklahoma, South Dakota, Utah, and Wyoming would be prices

reported for gas plant products at Conway less 7.0 cents for

transportation and fractionation.

We selected Mont Belvieu and Conway and divided the States among

these two market centers based on our judgment of where production from

these areas are transported for further fractionation and refining. The

8.0 cents per gallon for Mont Belvieu and the 7.0 cents per gallon for

Conway are the best estimate of the cost of transportation from the

areas plus the cost of fractionation. These estimates are not based on

a detailed survey.

A commercial price bulletin is a bulletin such as ``Platt's Oilgram

Price Report'' or the ``Bloomberg Report.'' The proposed rule would

permit a lessee to use any price bulletin, but the lessee must use the

same bulletin for all of a calendar year. The proposed rule would allow

a substitute price bulletin if the bulletin a lessee was using ceased

publication. The substitute bulletin would then be used for the rest of

the calendar year.

If a lessee uses a commercial price bulletin that is published

monthly, the monthly average minimum price is the minimum price

reported by the bulletin. If a lessee uses a commercial price bulletin

that is published weekly, the monthly average minimum price is the

arithmetic average of the weekly minimum prices reported by the

bulletin. If a lessee uses a commercial price bulletin that is

published daily, the monthly average minimum price is the arithmetic

average of the minimum prices reported by the bulletin for each

Wednesday of the month.

MMS specifically requests comments on this proposal. Comments

should address the following issues:

Is a minimum value needed when a lessee chooses the actual

dual accounting methodology?

Are there other better methods to use?

Are Conway and Mont Belvieu the proper locations to look

for prices for gas plant products?

Are the 7.0 and 8.0 cents per gallon the right deductions

for transportation and fractionation?

Would a percentage of the price or actual rates paid be a

better deduction?

The remaining provisions of proposed Sec. 206.174 are essentially

the same as the existing rules except that the two duplicative sections

applicable to unprocessed gas and processed gas would be consolidated

into one section.

The Committee also believed that verification of value in certain

areas without an index should be accomplished in a shorter period of

time. The proposed rule includes a new provision in Sec. 206.174(l)

that for leases in Montana and North Dakota, lessees must make

adjustments sooner, and MMS must complete its audits sooner than either

has done historically. The rule would be limited to Indian leases in

these two States because at this time there are no acceptable published

indexes applicable to that area.

Therefore, under this section, if value is determined without

deduction of a transportation or processing allowance, or if the

allowance is determined under an arm's- length contract, a lessee must

make all adjustments to value within 13 months of the production month.

MMS must conclude any audit and order any adjustments to royalty value

within 12 months after the adjustment reporting date. MMS has been

defined to include Tribal auditors where appropriate acting under

agreements pursuant to the Federal Oil and Gas Royalty

[[Page 49900]]

Management Act or other applicable agreements. As explained below,

there are circumstances where these dates would be extended.

For royalty value which is determined using a non-arm's-length

transportation or processing allowance, all adjustments must be made

within 9 months of the submittal of the actual cost allowance report to

MMS. MMS must conclude any audit and order any adjustments to royalty

value within 12 months after the adjustment reporting date. If the

lessee has both allowances, the period runs from the date MMS receives

the later of the two reports.

The proposed rule provides exceptions to the time limit on

completing audits and issuing orders. These exceptions are:

When disputes exist between lessees and purchasers,

transporters or processors, the time period for the lessee to make

adjustments would extend until 6 months after resolution of the

dispute. The period to audit and issue demands would be correspondingly

extended;

When the lessee and MMS agree to extend the time;

When there is a pending regulatory proceeding by any

agency with jurisdiction over gas sales prices (e.g., the Federal

Energy Regulatory Commission or a State public utility commission), the

time period for the lessee to make adjustments is extended for 90 days

after that proceeding concludes (including judicial review). The period

to audit and issue demands would be correspondingly extended;

When the lessee fails or refuses to provide records or

information necessary to complete the audit, the time period to issue

demands or orders will be extended for any time periods that MMS cannot

obtain the information. Thus, if MMS is required to issue a subpoena

and it takes 2 years of judicial proceedings to enforce the subpoena,

the time period to issue demands or orders would be extended until 12

months after those proceedings conclude;

When the lessee intentionally misrepresents or conceals a

material fact for the purpose of avoiding royalties, the time period to

complete audits or issue demands, or orders would not be applicable.

This proposed section also would expressly provide that if a lessee

becomes aware of an underpayment during the time period that

adjustments may be made, it is required to report that adjustment.

During an audit, if it is determined that the lessee made overpayments,

the lessee may credit the overpayments for a lease against any

underpayments on that same lease only discovered during the audit.

The proposed rule also would limit the time period for which MMS

could issue a demand or order. Proposed paragraph (l)(3) would define

demand or order to include restructured accounting orders that are

based on repeated, systemic errors for a significant number of leases

or a single lease for a significant number of reporting months. The

restructured accounting order must specify the reason and factual basis

for the order.

Section 206.175 How To Determine Quantities and Qualities of

Production for Computing Royalties

This section would be removed, and a new Sec. 206.175 would be

proposed and would retain some of the existing regulations and also

include some new provisions. The proposal revises existing language in

this section to reflect new provisions for computing royalties. The

Committee agreed to add Btu quality information to Form MMS-3160,

Monthly Report of Operations, for each well. With this additional

information, the Indian lessors and MMS could verify if the dual

accounting alternative increment method was calculated correctly.

Valuation rules for production from Indian leases always have

provided that a lessee must pay royalty for residue gas and gas plant

products based on its share of the monthly net output of the plant. The

problem was that lessees could not do this if they did not have access

to plant data. Therefore, under the proposed rule, if a lessee has no

ownership interest in the plant and does not operate the plant, it may

use its contract volume allocation to determine its share of output.

However, if the lessee has an ownership interest in the plant or if it

operates the plant, then it must use calculated volumes as in the

existing rules.

Section 206.176 How To Do Accounting for Comparison

This section would be removed, and a new Sec. 206.176 is proposed

to clarify when lessees must perform accounting for comparison under

the proposed valuation methods and procedures in this subpart E. In

summary:

Accounting for comparison is required when gas is

processed;

When accounting for comparison is required, the lessee may

use either actual dual accounting as described earlier in this preamble

or the alternative valuation method described in Sec. 206.173;

If any gas flowing through a facility measurement point is

processed, then all gas flowing through the facility measurement point

is considered processed except as discussed below.

To avoid accounting for comparison, a lessee must certify

the gas was never processed prior to entering the pipeline with an

index located in an index zone on Form MMS-4410.

Generally, if any gas production for a month is subject to dual

accounting, that value sets the minimum value for all lease production

that month. However, if any gas production from a lease for a month is

processed, but the weighted average Btu quality is less than 1,000 Btu/

cf, a different calculation is required. The proposed rule provides

that the alternative method for dual accounting can be applied only to

the volumes of gas production measured at the facility measurement

point that exceeds 1,000 Btu/cf. Also, no dual accounting is required

for the volumes of gas production measured at the facility measurement

point which is less than 1,000 Btu/cf. This is discussed earlier in the

preamble section discussing Sec. 206.173.

Section 206.177 General Provisions Regarding Transportation Allowances

This section would be removed, and a new Sec. 206.177 is proposed

to recognize that while transportation allowances are not relevant to

the proposed index-based valuation method at Sec. 206.172, they are

relevant to valuation in the following gas production situations at

Sec. 206.174:

For leases not in an index zone;

When gas is dedicated from a specific well or lease to a

sales contract; and

Non-Btu components of the gas stream.

For these situations, when a lessee values gas at a point distant

from the lease, this section would authorize a transportation allowance

for the reasonable actual costs of transporting gas to that distant

point. The transportation allowance would be applicable to unprocessed

gas, residue gas, and gas plant products. The lessee would be subject

to the existing 50-percent limitation of the proceeds at the point

distant from the lease. The proposed rule states that a lessee may not

deduct any allowance for gathering costs, a defined term.

The other general transportation allowance provisions would remain

the same.

Section 206.178 How To Determine a Transportation Allowance

This section would be removed, and a new Sec. 206.178 is proposed

to continue to differentiate between arm's-length

[[Page 49901]]

and non-arm's-length transportation contracts.

In Sec. 206.178(a)(1)(i), for arm's-length transportation

contracts, the proposed section would remove the requirement for a

lessee to pre-file Form MMS-4295, Gas Transportation Allowance Report,

before deducting a transportation allowance. In its place, the lessee

would be required to submit to MMS a copy of any transportation

contract, including amendments, the lessee used as a basis for the

reported allowance. Those documents, to the extent not previously

provided, are due to MMS within 2 months of when the lessee reported

the transportation deduction on Form MMS-2014.

The Committee believes this change will ease the burden on industry

and still provide MMS with documents useful to verify the allowance

claimed. Written contracts will not necessarily be required. For

example, in a situation where the sale is to a mainline pipeline and

there is no contract, the lessee would submit to MMS the copy of the

invoice it received from the mainline pipeline company to support its

transportation costs.

In the new Sec. 206.178(b)(1) for non-arm's-length transportation

or no contract situations, MMS would remove the requirement that a

lessee submit a completed Form MMS-4295 before deducting a

transportation allowance on Form MMS-2014. Rather, MMS would require

the lessee to submit its actual cost information (supporting its

allowance taken) within 3 months after the end of the calendar year

period (or other MMS-approved period) for which the allowance pertains.

MMS may approve a longer time period and would continue to ensure that

deductions are reasonable and allowable.

To further simplify the royalty valuation calculation, the

Committee recommended to allow a lessee to use a simple percentage

calculation of the proceeds in situations where the transportation was

non-arm's-length. Therefore, under Sec. 206.178(c), the authorized

allowance would be a fixed 10 percent of the gross value (not to exceed

30 cents per MMBtu) at the sales point. The percentage method would be

available to a lessee only if the transportation was provided at least

in part through a lessee-owned transportation system.

The lessee would have to elect to use either the transportation

allowance percentage or actual cost method for 1 year. The election

would apply to all of the lessee's leases in a designated area. The

lessee may elect to begin using the percentage method at the beginning

of any month. The first election to use the percentage method would be

effective from the time of election through the end of the following

calendar year.

The Committee agreed to permit a percentage of proceeds to

determine a transportation allowance to simplify the gas valuation

regulations and to ease administration for lessees, lessors, and MMS.

The Committee agreed to using 10 percent mainly to match the percentage

it derived in the index-based value. However, to ensure the percentage

reflects other similar allowances, MMS would have to periodically

review the validity of the percentage. In addition, MMS's

disqualification of an index zone would automatically require MMS to

review and determine if a new percentage better reflects current

transportation rates. Until such time as a new percentage had been

established, the lessee would be allowed to use either actual costs of

transportation or 10 percent of the gross value at the sales point.

From the existing Sec. 206.177(c), Reporting requirements, MMS

would retain only the requirement that the lessee must report

transportation allowance deductions as a separate item on Form MMS-

2014, unless MMS approves a different reporting procedure and must

submit all information to MMS to support Form MMS-4295 at the request

of MMS. All other provisions regarding allowance filings would be

removed.

Section 206.179 General Provisions Regarding Processing Allowances

MMS would remove this section and propose a new Sec. 206.179 and

Sec. 206.180 below.

The extraordinary cost allowance would be eliminated. MMS believes

at this time that it would be a better exercise of the Secretary's

trust responsibility to not allow extraordinary cost allowance for

Indian leases. We also would not allow any allowance in excess of two-

thirds of the value of the marketable product. This was not a Committee

proposal.

Section 206.180 How to Determine an Actual Processing Allowance

Section 206.180 would be added. MMS would not require that a lessee

file Form MMS-4109, Gas Processing Allowance Summary Report, on arm's-

length processing contracts.

MMS proposes that in place of these forms, MMS would continue to

require that a lessee submit arm's-length processing contracts,

agreements, and related documents within 2 months of reporting an

allowance deduction on Form MMS-2014.

MMS would remove the requirement for the lessee to submit a

completed Form MMS-4109 before deducting its non-arm's-length

processing costs on Form MMS-2014. Proposed Sec. 206.180(b)(3) would

provide that processing allowances under paragraph (b) must be

determined based on a calendar year or other MMS-approved period.

The proposed rule would retain the requirement that upon MMS's

request the lessee must submit all data it used to determine its

processing allowance, and that processing allowances be reported as a

separate item on Form MMS-2014, unless MMS approves a different

reporting procedure.

MMS would not require pre-approval or pre-filing of processing

allowances, but would retain interest assessments for any underpayment

of royalties caused when a lessee erroneously deducted a processing

allowance.

Section 206.181 Processing Allowances for Use in Certain Dual

Accounting Situations

MMS would add this proposed new section to address how to apply

processing allowances in cases where the lease requires dual accounting

but the gas is not processed by or on behalf of the lessee. The

proposed section provides four benchmarks the lessee would follow in

these situations.

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 Indian leases. These changes would add

several alternative valuation methods to the existing regulations.

Small entities are encouraged to comment on this proposed rule.

Unfunded Mandates Reform Act of 1995

The Department of the Interior has determined and certifies

according to the Unfunded Mandates Reform Act, 2 U.S.C. 1502 et seq.,

that this rule will not impose a cost of $100 million or more in any

given year on local, Tribal, State governments, or the private sector.

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

[[Page 49902]]

Executive Order 12630, Government Action and Interference with

Constitutionally Protected Property Rights.

Executive Order 12988

The Department has certified to the Office of Management and Budget

that this proposed rule meets the applicable civil justice reform

standards provided in sections 3(a) and 3(b)(2) of Executive Order

12988.

Executive Order 12866

This document has been reviewed under Executive Order 12866 and is

not a significant regulatory action requiring Office of Management and

Budget review.

Paperwork Reduction Act

This proposed rule contains two collections of information which

have been submitted to the Office of Management and Budget (OMB) for

review and approval under section 3507(d) of the Paperwork Reduction

Act of 1995. As part of our continuing effort to reduce paperwork and

respondent burden, MMS invites the public and other Federal agencies to

comment on any aspect of the reporting burden. Submit your comments to

the Office of Information and Regulatory Affairs, OMB, Attention Desk

Officer for the Department of the Interior, Washington, DC 20503. Send

copies of your comments to: Minerals Management Service, Royalty

Management Program, Rules and Procedures Staff, PO Box 25165, MS 3101,

Denver, Colorado, 80225-0165; courier address is: Building 85, Denver

Federal Center, Denver, Colorado 80225; e:Mail address is:

David__G[email protected].

One collection of information is titled ``Certification for Not

Performing Accounting for Comparison (Dual Accounting).'' Accounting

for comparison (dual accounting) is required by the terms of most

Indian leases when gas produced from the lease is processed. To avoid

dual accounting, a lessee must certify, using proposed Form MMS-4410

(Attachment 1), that the gas was never processed prior to entering the

pipeline with an index located in an index zone. The lessee will be

required to sign the certification form for each property having

production that is exempt from dual accounting. This is a one time

certification that will remain in effect until there is a change in

lease status or ownership. This requirement will assist the Indian

lessor in receiving all the royalties that are due and aid MMS in its

compliance efforts.

Rules establishing the use of Form MMS-4410 to certify that gas

production is not processed before it flows into a pipeline with an

index but which may be processed later are at proposed 30 CFR

206.172(b)(1)(ii). The lessee or operator of an Indian lease will

certify to MMS that gas produced from the lease specified on the form

is not processed before entering a pipeline with an index located in an

index zone. This certification will allow MMS and the tribes to better

monitor compliance with the dual accounting requirement of Indian

leases.

In most cases, the lessee or operator will directly know the

disposition of the gas. If gas is sold at the wellhead, the lessee or

operator may have to consult with the purchaser of the gas to find its

disposition. Information provided on the forms may be used by MMS

auditors, Valuation and Standards Division (VSD), and the Office of

Indian Royalty Assistance.

MMS estimates the annual reporting burden to be approximately 5,412

hours. There are approximately 4,511 tribal and allotted Indian leases

and 935 payors comprising the Indian lease universe. The MMS subject

matter experts estimate that at most 30 percent of the Indian leases

(1,353 leases) would not require accounting for comparison and would

submit the certification forms. This one time filing as required by 30

CFR 206.172 (b)(1)(ii) could require about 3 hours per report to

extract the data from company records or obtain the information from

the purchaser. The certification will remain in effect until there is a

change in lease status or ownership. Only a minimal recordkeeping

burden would be imposed by this collection of information. Based upon

$25 per hour, one time cost to industry is estimated to be $135,300.

The other collection of information contained in this proposed rule

is titled ``Safety Net Report.'' The safety net calculation establishes

the minimum value for royalty purposes. This requirement will assist

the Indian lessor in receiving all the royalties that are due and aid

MMS in its compliance efforts. The safety net price would be calculated

using prices received for gas sold downstream of the index point. It

would include only the lessee's sales prices, and it would not require

detailed calculations for the costs of transportation. By June 30

following each calendar year, the lessee would be required to calculate

for each month of the calendar year a safety net price. This must be

calculated for each index zone where the lessee has an Indian lease.

The safety net price would capture the significantly higher-values for

sales occurring beyond the index point. The lessee would submit its

safety net price to MMS annually (by June 30) using Form MMS-4411

(Attachment 2).

Rules establishing the use of Form MMS-4411 to report the safety

net price are at proposed 30 CFR 206.172(e). The lessee would compare

the amount that is 80 percent of the safety net price to the amount

that is 125 percent of the monthly index value for the index zone. The

lessee would owe additional royalties plus late-payment interest if 125

percent of the index value were less than 80 percent of the safety net

price. The MMS would have 1 year from the date it receives the lessee's

Form MMS-4411 providing the safety net price to order the lessee to

amend its safety net price calculation. If MMS did not order any

adjustment to the safety net price, the safety net price would be final

for the lessee. This report will allow MMS and the tribes to ensure

that Indian mineral lessors receive the maximum revenues from mineral

resources on their land consistent with the Secretary's trust

responsibility and lease terms.

The lessee or operator will directly know the disposition of the

gas and the safety net price would include only the lessee's sales

prices. The lessee would only include sales under those contracts that

establish a delivery point beyond the first index pricing point to

which the gas flows. Moreover, those contracts must include gas

attributable to one or more of the lessee's Indian leases in the index

zone. Information provided on the forms may be used by MMS auditors,

Valuation and Standards Division (VSD), and the Office of Indian

Royalty Assistance.

MMS estimates the annual reporting burden to be approximately

37,400 hours. About 935 companies pay royalties on approximately 4,511

tribal and allotted Indian leases. MMS subject matter experts estimate

that about 24 hours are required per report to extract from company

records the data required at proposed 30 CFR 206.172 (e). They also

estimate that about 20 percent of the companies have sales beyond the

first index pricing point. Therefore, reports from about 187 companies

(.20 x 935) for 8 index zones are required annually. Only a minimal

recordkeeping burden would be imposed annually by this collection of

information. Based upon $25 per hour, annual costs to industry is

estimated to be $935,000.

In compliance with the requirement of section 3506 (c)(2)(A) of the

Paperwork Reduction Act of 1995, MMS is providing notice and otherwise

consulting with members of the public

[[Page 49903]]

and affected agencies concerning collection of information in order to

solicit comment to: (a) Evaluate whether the proposed collection of

information is necessary for the proper performance of the functions of

the agency, including whether the information shall have practical

utility; (b) evaluate the accuracy of the agency's estimate of the

burden of the proposed collection of information; (c) enhance the

quality, utility, and clarity of the information to be collected; and

(d) minimize the burden of the collection of information on those who

are to respond, including through the use of automated collection

techniques or other forms of information technology.

The Paperwork Reduction Act of 1995 provides that an agency may not

conduct or sponsor, and a person is not required to respond to, a

collection of information unless it displays a currently valid OMB

control number.

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. Sec. 4332(2)(C)) is not

required.

List of Subjects in 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.

Dated: September 6, 1996.

Bob Armstrong,

Assistant Secretary--Land and Minerals Management.

For the reasons set out in the preamble, Parts 202 and 206 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 continues to read as

follows:

Authority: 5 U.S.C. 301 et seq.; 25 U.S.C. 396 et seq., 396a et

seq., 2101 et seq.; 30 U.S.C. 181 et seq., 351 et seq., 1001 et

seq., 1701 et seq.; 31 U.S.C. 9701; 43 U.S.C. 1301 et seq., 1331 et

seq., 1801 et seq.

2. The heading for Subpart D--Federal and Indian Gas--is revised to

read as follows:

Subpart D--Federal Gas

3. Section 202.51(b) is revised to read as follows:

* * * * *

(b) The definitions in subparts C, D, E, and I of part 206 of this

title are applicable to subparts B, C, D, I, and J of this part.

4. Sections 202.150 (b)(1), (e)(1), and (e)(2) are amended by

removing the words ``or Indian''.

5. Section 202.150 paragraph (f) introductory text is amended by

removing the words ``and Indian,'' and paragraph (f)(3) by removing the

words ``or Indian.''

6. Section 202.151(a)(2) is amended by removing the words ``and

Indian.''

7. A new subpart J is added to read as follows:

Subpart J--Gas Production From Indian Leases

Sec.

202.550 How to determine the royalty due on gas production.

202.551 Standards for reporting and paying royalties on gas.

Subpart J--Gas Production From Indian Leases

Sec. 202.550 How to determine the royalty due on gas production.

This section explains how lessees and other royalty payors must

determine and pay royalties on gas production from Indian leases

subject to this subpart.

(a) Royalty rate. (1) You must calculate royalties due on gas

production from Indian leases using the royalty rate in the lease. You

must pay royalty in value unless the Tribal lessor, or the Secretary of

the Department of the Interior (Secretary) for allottee leases,

requires payment in kind. When paid in value, the royalty due is the

value, for royalty purposes, determined under 30 CFR part 206

multiplied by the royalty rate in the lease.

(2) If you demonstrate economic hardship, you may request a royalty

rate reduction which is subject to the approval of the Indian lessor

and the Secretary.

(b) Leases not in an approved Federal agreement (AFA). You must pay

royalty on your entitled share of gas production from your Indian

lease, except as provided in paragraphs (d), (e), and (f) of this

section. You may pay on your takes if you notify the Associate Director

for Royalty Management in writing that all other persons paying

royalties on the lease also agree to pay on their takes. If you pay

royalties based on your takes that are less than your entitled share,

you are still liable for the royalties on your entitled share if the

person taking the production does not pay the royalties owed.

(c) Leases in an approved Federal agreement (AFA). (1) You must pay

royalties on production allocated to your lease under the terms of an

AFA in accordance with the following requirements:

(i) Royalty rate--You must pay royalties based on the royalty rate

specified in the lease. The lessee and the Indian lessor may agree to

amend the royalty rate in the lease with the Secretary's approval.

(ii) Volume--You must pay royalties each month on your entitled

share of production allocated to your lease under the terms of an AFA.

This may include production from more than one AFA.

(iii) Value--The value of production that you take must be

determined under 30 CFR part 206. If you take more than your entitled

share of production for any month, the value of your entitled share is

the weighted-average value of the production, determined under 30 CFR

part 206, that you take during that month.

(iv) The value of production that you are entitled to but do not

take for any month must be determined as follows:

(A) Where you take only a portion of your entitled share of

production from a lease in an AFA, value for the undertaken volumes

must be based on the weighted average of the value of the production

you do take for that month from the same lease in the same AFA as

determined under 30 CFR part 206. You may apply this valuation method

only if you take a significant volume of production. If you do not take

a significant volume of production from your lease for a month, you

must use paragraph (c)(1)(iv)(B) or (C)(1)-(5) of this section

whichever is applicable.

(B) If you take none of your entitled share of production in an AFA

and that production would have been valued using an index-based method

under Sec. 206.172(b) of this title had it been taken, then you must

determine the value of production not taken for that month under

Sec. 206.172(b) of this title as if you had taken it.

(C) If you take none of your entitled share of production from a

lease in an AFA and that production cannot be valued under

Sec. 202.550(c)(1)(iv)(B), then you must determine the value of

production not taken for that month based on the first applicable

method as follows:

(1) The weighted average of the value of your production (under 30

CFR Part 206) from other leases in the same AFA that month;

[[Page 49904]]

(2) The weighted average of the value of your production (under 30

CFR Part 206) from other leases in the same field or area that month;

(3) The weighted average of the value of your production (under 30

CFR Part 206) during the previous month for production from leases in

the same AFA that month;

(4) The weighted average of the value of your production (under 30

CFR Part 206) during the previous month for production from other

leases in the same field or area; or

(5) The latest major portion value you received from MMS calculated

under 30 CFR 206.174 for the same MMS-designated area.

(2) If you take less than your entitled share of AFA production for

any month, but you pay royalties on the full volume of your entitled

share in accordance with the provisions of this section, you will owe

no additional royalty for that lease for that month when you later take

more than your entitled share to balance your account. This also

applies when the other AFA participants pay you money to balance your

account.

(d) Gas subject to royalty. (1) All gas produced from or allocated

to your Indian lease is subject to royalty except:

(i) Gas that is unavoidably lost;

(ii) Gas that is used on, or for the benefit of, the lease;

(iii) Gas that is used off-lease for the benefit of the lease when

the Bureau of Land Management (BLM) approves such off-lease use; and

(iv) Gas used as plant fuel as provided in 30 CFR 206.179(e).

(2) You may use royalty-free only that proportionate share of each

lease's production (actual or allocated) necessary to operate the

production facility when you use gas:

(i) On, or for the benefit of, the lease at a production facility

handling production from more than one lease with BLM's approval; or

(ii) At a production facility handling unitized or communitized

production.

(3) If the terms of your lease are inconsistent with this subpart,

your lease terms will govern to the extent of that inconsistency.

(e) Avoidably lost, wasted, or drained gas and compensatory

royalty. If BLM determines that a volume of gas was avoidably lost or

wasted, or a volume of gas was drained from your Indian lease for which

compensatory royalty is due, then you must determine the value of that

volume of gas in accordance with 30 CFR part 206.

(f) Insurance compensation. If you receive insurance compensation

for unavoidably lost gas, you must pay royalties on the amount of that

compensation. This paragraph does not apply to compensation through

self-insurance.

(v) Reporting and payment--You must report and pay royalties as

provided in part 218 of this title.

Sec. 202.551 Standards for reporting and paying royalties on gas.

This section provides technical standards for reporting and paying

royalties on gas produced from Indian leases.

(a)(1) You must determine gas volumes and Btu heating values, if

applicable, under the same degree of water saturation. You must report

gas volumes 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 pounds per square inch absolute (psia) and a

standard temperature base of 60 deg.F. You must report gas volumes and

Btu heating values, for royalty purposes, on the same water vapor

saturated or unsaturated basis that the Federal Energy Regulatory

Commission (FERC) prescribes in its regulations. You may use the basis

prescribed in your gas sales contract as long as the sales contract

does not conflict with FERC's regulations.

(2) You must use the frequency and method of Btu measurement stated

in your contract to determine Btu heating values for reporting

purposes. However, you must measure the Btu value at least semi-

annually by recognized standard industry testing methods even if your

contract provides for less frequent measurement.

(b) Residue gas and gas plant product volumes must be reported as

follows:

(1) You must report carbon dioxide (CO2), nitrogen (N2),

helium (He), residue gas, and any gas marketed as a separate product by

using the same standards specified in paragraph (a) of this section.

(2) You must report natural gas liquid (NGL) volumes in standard

U.S. gallons (231 cubic inches) at 60 deg.F.

(3) You must report sulfur (S) volumes in long tons (2,240 pounds).

PART 206--PRODUCT VALUATION

8. The authority citation for Part 206 continues to read as

follows:

Authority: 5 U.S.C. 301 et seq.; 25 U.S.C. 396 et seq., 396a et

seq., 2101 et seq.; 30 U.S.C. 181 et seq., 351 et seq., 1001 et

seq., 1701 et seq.; 31 U.S.C. 9701.; 43 U.S.C. 1301 et seq., 1331 et

seq., and 1801 et seq.

9. Subpart E of part 206 is revised to read as follows:

Subpart E--Indian Gas

Sec.

206.170 What this subpart applies to.

206.171 Definitions.

206.172 How to value gas produced from leases in an index zone.

206.173 Alternative methodology for dual accounting.

206.174 How to value gas production when an index-based method

cannot be used.

206.175 How to determine quantities and qualities of production for

computing royalties.

206.176 How to do accounting for comparison.

206.177 General provisions regarding transportation allowances.

206.178 How to determine a transportation allowance.

206.179 General provisions regarding processing allowances.

206.180 How to determine an actual processing allowance.

206.181 Processing allowances for use in certain dual accounting

situations.

Subpart E--Indian Gas

Sec. 206.170 What this subpart applies to.

This subpart provides royalty valuation provisions applicable to

Indian lessees.

(a) This subpart applies to all gas production from Indian (Tribal

and allotted) oil and gas leases (except leases on the Osage Indian

Reservation). 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 Federal leases.

(b) If the specific provisions of any Federal statute, treaty,

negotiated agreement, settlement agreement resulting from any

administrative or judicial proceeding, or Indian oil and gas lease are

inconsistent with any regulation in this subpart, then the Federal

statute, treaty, negotiated agreement, settlement agreement, or lease

will govern to the extent of that inconsistency.

(c) You may calculate the value of production for royalty purposes

under methods other than those the regulations in this title require,

but only if you, the tribal lessor, and MMS jointly agree to the

valuation methodology. For leases that Indian allottees own, you and

MMS must agree to the valuation methodology.

(d) All royalty payments you make to MMS are subject to monitoring,

review, audit, and adjustment.

(e) The regulations in this subpart are intended to ensure that the

trust responsibilities of the United States with respect to the

administration of Indian oil and gas leases are discharged in

accordance with the requirements of

[[Page 49905]]

the governing mineral leasing laws, treaties, and lease terms.

Sec. 206.171 Definitions.

The following definitions apply to this subpart and to subpart J of

part 202 of this title:

Accounting for comparison means the same as dual accounting.

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 index zone.

Allowance means a deduction in determining value for royalty

purposes. Processing allowance means an allowance for the reasonable

actual costs of processing gas determined under this subpart.

Transportation allowance means an allowance for the reasonable actual

cost of transportation determined under this subpart.

Approved Federal agreement (AFA) means a unit or communitization

agreement approved under Department of the Interior (DOI) regulations.

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/or legal characteristics.

An area may encompass all lands within the boundaries of an Indian

reservation.

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. 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:

(1) Ownership in excess of 50 percent constitutes control;

(2) Ownership of 10 through 50 percent creates a presumption of

control;

(3) 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.

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 the percentage of

ownership or control of the entity. 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 persons who pay royalties,

rents, or bonuses on Indian leases.

BIA means the Bureau of Indian Affairs of the Department of the

Interior.

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.

Dual Accounting (or accounting for comparison) refers to the

requirement to pay royalty based on a value which is the higher of the

value of gas prior to processing less any applicable allowances as

compared to the combined value of drip condensate, residue gas, and gas

plant products after processing, less applicable allowances.

Entitlement (or entitled share) means the gas production from a

lease, or allocable to lease acreage under the terms of an AFA

multiplied by the operating rights owner's percentage of interest

ownership in the lease or the acreage.

Facility measurement point (or point of royalty settlement) means

the point where the BLM-approved measurement device is located for

determining the volume of gas removed from the lease. The facility

measurement point may be on the lease or off-lease with BLM approval.

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.

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 lease production to: a central

accumulation and/or treatment point on the lease, unit, or communitized

area; or a central accumulation or treatment point off the lease, unit,

or communitized area as approved by BLM operations personnel.

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, and 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 Indian lessor, 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 Indian royalty interest is 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

[[Page 49906]]

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 any point on a pipeline for which

there is an index.

Index zone means a field or an area with an active spot market and

published indices applicable to that field or area that are acceptable

to MMS under Sec. 206.172(d)(4) of this subpart.

Indian allottee means any Indian for whom land or an interest in

land is held in trust by the United States or who holds title subject

to Federal restriction against alienation.

Indian Tribe means any Indian Tribe, band, nation, pueblo,

community, rancheria, colony, or other group of Indians for which any

land or interest in land is held in trust by the United States or which

is subject to Federal restriction against alienation.

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 Federal leases.

Lease products means any leased minerals attributable to,

originating from, or allocated to a lease.

Lessee means any person to whom the United States, a Tribe, and/or

individual Indian landowner 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.

Major portion means the lease term providing that the royalty value

may be established considering the highest price paid or offered for

the major portion of production in the field or area.

Marketable condition means lease products which are sufficiently

free from impurities and otherwise in a condition that a purchaser will

accept them under a sales contract typical for the field or area.

MMS means the Minerals Management Service, Department of the

Interior. MMS includes, where appropriate, Tribal auditors acting under

agreements under the Federal Oil and Gas Royalty Management Act, 30

U.S.C. 1701 et seq. or other applicable agreements.

Minimum royalty means that minimum amount of production royalty

that the lessee must pay for the lease year as specified in the lease

or in applicable leasing regulations.

Natural gas liquids (NGL's) means those gas plant products

consisting 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, and/or manufacturing are deducted from

the proceeds received for, or 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.

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.

Operating rights owner (working interest owner) means any 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)).

Person means any individual, firm, corporation, association,

partnership, consortium, or joint venture (when established as a

separate entity).

Point of royalty measurement means the same as facility measurement

point.

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.

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.

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. It also does not normally require a cancellation notice

to terminate, and does not contain an obligation, or 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.

Work-back method means the same as net-back method.

Sec. 206.172 How to value gas produced from leases in an index zone.

(a) What leases this section applies to. (1) This section explains

how lessees must value, for royalty purposes, gas produced from Indian

leases located in an index zone. For other leases, value must be

determined under Sec. 206.174 of this subpart, or as otherwise provided

in the lease. You must use the valuation provision of this section if

your lease is in an index zone and:

(i) Has a major portion provision, or

(ii) Does not have a major portion provision, but the lease

provides for the Secretary to determine the value of production.

(2) This section does not apply to carbon dioxide, nitrogen, or

other non-hydrocarbon components of the gas stream. However, if they

are recovered and sold separately from the gas stream, the value for

these products must be determined under Sec. 206.174 of this subpart.

(b) How to value residue gas and gas prior to processing. (1)

Except as provided in paragraph (e) of this section, this paragraph (b)

explains how you must value:

(i) Gas production prior to processing;

(ii) Gas production that you certify on Form MMS-4410 is not

processed

[[Page 49907]]

before it flows into a pipeline with an index but which may be

processed later; and

(iii) Residue gas after processing.

(2)(i) Except as provided in paragraph (b)(2)(ii) of this section,

the value of gas production which is not sold under dedicated contracts

is the index-based value determined in paragraph (d) of this section.

(ii) If gas not sold under a dedicated contract was subject to a

previous contract which was the subject of a gas contract settlement,

then you must compare the index-based value determined in paragraph (d)

of this section with the value of that gas under Sec. 206.174. You must

pay royalty on the higher of those two values.

(3) The value of gas production which is sold under dedicated

contracts is the higher of the index-based value under paragraph (d) of

this section or the value of that production determined under

Sec. 206.174 of this subpart.

(c) How to value gas that is processed before it flows into a

pipeline with an index. Except as provided in paragraph (e) of this

section, this paragraph (c) explains how you must value gas that is

processed before it flows into a pipeline with an index. You must value

such gas production based on the higher of:

(1) The value of the gas prior to processing determined under

paragraph (b) of this section; or

(2) The value of the gas after processing, which is either the

alternative dual accounting value under Sec. 206.173 of this subpart or

the sum of:

(i) The value of the residue gas determined under paragraph (b)(2)

or (b)(3) of this section, as applicable; and

(ii) The value of the gas plant products determined under

Sec. 206.174 of this subpart, less any applicable processing allowances

determined under this subpart; and

(iii) The value of any drip condensate associated with the

processed gas determined under subpart B of this part.

(d) How to determine the index-based value for gas production. (1)

To determine the index-based value per MMBtu for production from a

lease in an index zone, you must:

(i) For each MMS-approved publication, calculate the average of the

highest reported prices for all index pricing points in the index zone,

except for any prices excluded under paragraph (d)(6) of this section;

(ii) Sum the averages calculated in paragraph (d)(1)(i) of this

section and divide by the number of publications;

(iii) Reduce the number calculated under paragraph (d)(1)(ii) of

this section by 10 percent, but not by less than 10 cents per MMBtu or

more than 30 cents per MMBtu. The result is the index-based value per

MMBtu for production from all leases in that index zone.

(2) MMS will publish in the Federal Register the index zones that

are eligible for the index-based valuation method under this paragraph.

MMS will monitor the market activity in the index zones and, if

necessary, hold a technical conference to add or modify a particular

index zone. Any change to the index zones will be published in the

Federal Register. MMS will consider the following factors and

conditions in determining eligible index zones:

(i) Areas for which MMS-approved publications establish index

prices that accurately reflect the value of production in the field or

area where the production occurs;

(ii) Common markets served;

(iii) Common pipeline systems;

(iv) Simplification; and

(v) Easy identification in MMS' systems, such as counties or Indian

reservations.

(3) If market conditions change so that an index-based method for

determining value is no longer appropriate for an index zone, MMS will

hold a technical conference to consider disqualification of an index

zone. MMS will publish notice in the Federal Register if an index zone

is disqualified. If an index zone is disqualified, then production from

leases in that index zone cannot be valued under this paragraph.

(4) MMS periodically will publish in the Federal Register a list of

acceptable publications based on certain criteria, including, but not

limited to:

(i) Publications buyers and sellers frequently use;

(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;

(iv) Publications which publish the range of reported prices they

use to calculate their index; and

(v) Publications independent from DOI, lessors, and lessees.

(5) Any publication may petition MMS to be added to the list of

acceptable publications.

(6) MMS may exclude an individual index price for an index zone in

an MMS-approved publication if MMS determines that the index price does

not accurately reflect the value of production in that index zone. MMS

will publish a list of excluded indices in the Federal Register.

(7) MMS will reference which tables in the publications you must

use for determining the associated index prices.

(8) The index-based values determined under this paragraph are not

subject to deductions for transportation or processing allowances

determined under Secs. 206.177, 206.178, 206.179, and 206.180 of this

subpart.

(e) How you determine the minimum value for royalty purposes. (1)

Notwithstanding any other provision of this section, the value for

royalty purposes of gas production from an Indian lease subject to this

section cannot be less than the value determined under this paragraph

(e).

(2) By June 30 following any calendar year, you must calculate for

each month of that calendar year your safety net price per MMBtu using

the procedures in paragraph (e)(3) of this section. You must calculate

a safety net price for each month and for each index zone where you

have an Indian lease for which you report and pay royalties.

(3) Your safety net price for an index zone must be calculated as

the volume weighted average contract price per delivered MMBtu under

your arm's-length contracts for the disposition of residue gas or

unprocessed gas from the same index zone (which, for purposes of this

paragraph (e) only, includes gas from your Indian leases and Federal,

State, and fee properties). Do not reduce the contract price for any

transportation costs incurred to deliver the gas to the purchaser. You

should include in your calculation only sales under those contracts

that establish a delivery point beyond the first index pricing point to

which the gas flows and that include any gas attributable to one or

more of your Indian leases in the index zone. For purposes of paragraph

(e) of this section only, the contract price will not include:

(i) Any amounts which you receive in compromise or settlement of a

predecessor contract for that gas;

(ii) Adjustments for you or any other person to place gas

production in marketable condition or to market the gas; or

(iii) Any amounts related to marketable securities associated with

that sales contract.

(4)(i) Next, you must determine for each month the number that is

80 percent of the safety net price you calculated for an index zone

under paragraph (e)(3) of this section. You also must calculate the

number that equals 125 percent of the monthly index-based value. You

must perform this calculation separately for each index zone. For any

index zone, if the number you calculated as 80 percent of the safety

net price exceeds the number you calculated as 125 percent of the

index-based value, then you owe additional royalty on the safety net

differential

[[Page 49908]]

determined under paragraph (e)(4)(ii) of this section.

(ii) To calculate the additional royalties you owe, multiply the

safety net differential determined in paragraph (e)(4)(i) of this

section by the volume of all your gas production from Indian leases in

that index zone that was sold beyond the first index pricing point

through which the gas flowed and that was used in the calculation in

paragraph (e)(3) (``safety net production'').

(iii) Allocate the additional royalties determined under paragraph

(e)(4)(ii) of this section to each Indian lease in the index zone with

safety net production. For each Indian lease in the index zone with

safety net production, allocate the additional royalties owed as

follows:

[(A)/(B)] x (C)

Where:

(A) Is volume (in MMBtu's) of safety net production from that

Indian lease;

(B) Is volume (in MMBtu's) of safety net production from all your

Indian leases in that index zone; and

(C) Is total additional royalties owed.

(5) You have the following responsibilities to comply with the

minimum value for royalty purposes:

(i) You must report the safety net price for each index zone to MMS

on Form MMS-4411 no later than June 30 following each calendar year.

(ii) You must pay and report on Form MMS-2014 additional royalties

due no later than June 30 following each calendar year.

(iii) MMS has 1 year from the date it receives your Form MMS-4411

to order you to amend your safety net price calculation. If MMS does

not order any amendments within the 1-year period, your safety net

price calculation is final.

Sec. 206.173 Alternative methodology for dual accounting.

(a) Election for a dual accounting method. (1) If you are required

to perform the accounting for comparison (dual accounting) under

Sec. 206.176 of this subpart, you have two choices. You may elect to

perform the dual accounting calculation according to either

Sec. 206.176(a) of this subpart (called actual dual accounting), or

paragraph (b) of this section (called the alternative methodology for

dual accounting).

(2)(i) Your election to use the alternative methodology for dual

accounting must be made separately for your Indian leases in each MMS-

designated area. Your election for a designated area must apply to all

of your Indian leases in that area. MMS will publish in the Federal

Register a list of the leases that will be associated with each

designated area for purposes of this section. The MMS-designated areas

are:

(A) Alabama-Coushatta;

(B) Blackfeet Reservation;

(C) Crow Reservation;

(D) Fort Belknap Reservation;

(E) Fort Berthold Reservation;

(F) Fort Peck Reservation;

(G) Jicarilla Apache Reservation;

(H) MMS-designated groups of counties in the State of Oklahoma;

(I) Navajo Reservation;

(J) Northern Cheyenne Reservation;

(K) Rocky Boys Reservation

(L) Southern Ute Reservation;

(M) Turtle Mountain Reservation;

(N) Ute Mountain Ute Reservation;

(O) Uintah and Ouray Reservation;

(P) Wind River Reservation; and

(Q) Any other area that MMS designates. MMS will publish a new area

designation in the Federal Register.

(ii) You may elect to begin using the alternative methodology for

dual accounting at the beginning of any month. The first election to

use the alternative methodology will be effective from the time of

election through the end of the following calendar year. Thereafter,

each election to use the alternative methodology must remain in effect

for 2 calendar years. You may return to the actual dual accounting

method only at the beginning of the next election period or with the

written approval of MMS and the Tribal lessor for Tribal leases, and

MMS for Indian allottee leases in the designated area.

(iii) When you elect to use the alternative methodology, any new

wells or newly-acquired leases commencing production in the designated

area during the term of the election must use the alternative

methodology.

(b) How to calculate the alternative methodology for dual

accounting.

(1) The alternative methodology adjusts the value of gas prior to

processing determined under either Sec. 206.172 or Sec. 206.174 of this

subpart to provide an after-processing value. You must use the after-

processing value for royalty payment purposes. The amount of the

increase depends on your relationship with the owner(s) of the plant

where the gas is processed. If you have no direct or indirect ownership

interest in the processing plant, then the increase is lower. If you

have a direct or indirect ownership interest in the plant where the gas

is processed, the increase is higher.

(2)(i) To calculate the alternative methodology for dual

accounting, you must apply the increase to the value prior to

processing, determined in either Sec. 206.172 or Sec. 206.174 of this

subpart, as follows:

Post-processing value = (value determined in either Sec. 206.172 or

Sec. 206.174) x (1 + increment for dual accounting).

(ii) In this equation, the increment for dual accounting is the

number you take from the applicable Btu range in the following table:

------------------------------------------------------------------------

Increment Increment

if lessee if lessee

has no has an

BTU range ownership ownership

interest in interest in

plant plant

------------------------------------------------------------------------

1001 to 1050.................................. .0275 .0375

1051 to 1100.................................. .0400 .0625

1101 to 1150.................................. .0425 .0750

1151 to 1200.................................. .0700 .1225

1201 to 1250.................................. .0975 .1700

1251 to 1300.................................. .1175 .2050

1301 to 1350.................................. .1400 .2400

1351 to 1400.................................. .1450 .2500

1401 to 1450.................................. .1500 .2600

1451 to 1500.................................. .1550 .2700

1501 to 1550.................................. .1600 .2800

1551 to 1600.................................. .1650 .2900

1601 to 1650.................................. .1850 .3225

1651 to 1700.................................. .1950 .3425

1700+......................................... .2000 .3550

------------------------------------------------------------------------

(3) The applicable Btu for purposes of this section is the volume

weighted-average Btu for the lease computed from measurements at the

facility measurement point(s) for gas production from the lease.

(4) If you process any gas from the lease during a month and the

weighted-average quality of the gas from the lease that month

determined under paragraph (b)(3) of this section is:

(i) Greater than 1,000 Btu's per cubic foot (Btu/cf), all gas

production from the lease is subject to dual accounting, and you must

use the alternative method for all that gas production;

(ii) Less than or equal to 1,000 Btu/cf, only the volumes of lease

production measured at facility measurement points whose quality

exceeds 1,000 Btu/cf is subject to dual accounting, and you may use the

alternative methodology for these volumes. For gas measured at facility

measurement points for these leases where the quality is equal to or

less than 1,000 Btu/cf, you are not required to do dual accounting.

Sec. 206.174 How to value gas production when an index-based method

cannot be used.

(a)(1) This section applies to the valuation of gas production when

your lease is not in an index zone and any other gas production that

cannot be valued under Sec. 206.172 of this subpart. It also applies to

the valuation of gas from all Indian leases that is sold under a

dedicated contract, to the valuation of gas plant products, and to

components of the gas stream that have no Btu value

[[Page 49909]]

(for example, carbon dioxide, nitrogen, etc.). If your lease is in an

index zone and you sell your gas under a dedicated contract, then the

value of your gas is the higher of the value under this section or the

value under Sec. 206.172 of this subpart.

(2) The value of gas production, for royalty purposes, subject to

this subpart is the value of gas determined under this section less

applicable allowances determined under this subpart.

(3) You must determine the value of gas production that is

processed and is subject to accounting for comparison using the

procedure in Sec. 206.176 of this subpart.

(4)(i) This paragraph applies if your lease has a major portion

provision. It also applies if your lease does not have a major portion

provision but the lease provides for the Secretary to determine value.

The value of production you must initially report and pay is the value

determined in accordance with the other paragraphs of this section.

Within 90 days of each report month, MMS will determine the major

portion value and notify you in writing of that value. The value of

production for royalty purposes for your lease is the higher of either

the value determined under this section which you initially used to

report and pay royalties, or the major portion value calculated under

this paragraph (a)(4). If the major portion value is higher, you must

submit an amended Form MMS-2014 to MMS within 30 days of when you

receive written notice from MMS of the major portion value. Late-

payment interest under 30 CFR 218.54 on any underpayment will not begin

to accrue until the date the amended Form MMS-2014 is due to MMS.

(ii) MMS will calculate the major portion value for each designated

area (which are the same designated areas as under Sec. 206.173 of this

title) using values reported for unprocessed gas and residue gas on

Form MMS-2014 for gas produced from leases on that Indian reservation

or other designated area. MMS will array the reported prices from

highest to lowest price. The major portion value is that price at which

25 percent (by volume) of the gas (starting from the highest) is sold.

MMS cannot unilaterally change the major portion value after you are

notified in writing of what that value is for your leases.

(b)(1)(i) The value of gas, residue gas, or any gas plant product

you sell under an arm's-length contract is the gross proceeds accruing

to you, except as provided in paragraphs (b)(1) (ii) and (iii) of this

section. You have the burden of demonstrating that your contract is

arm's-length.

(ii) In conducting reviews and audits for gas valued based upon

gross proceeds under this paragraph, MMS will examine whether or not

your contract reflects the total consideration actually transferred

either directly or indirectly from the buyer to you for the gas,

residue gas, or gas plant product. If the contract does not reflect the

total consideration, then MMS may require that the gas, residue gas, or

gas plant product sold under that contract be valued in accordance with

paragraph (c) of this section. Value may not be less than the gross

proceeds accruing to you, including the additional consideration.

(iii) If MMS determines for gas valued under this paragraph that

the gross proceeds accruing to you under an arm's-length contract do

not reflect the value of the gas, residue gas, or gas plant products

because of misconduct by or between the contracting parties, or because

you otherwise have breached your duty to the lessor to market the

production for the mutual benefit of you and the lessor, then MMS will

require that the gas, residue gas, or gas plant product be valued under

paragraphs (c)(2) or (c)(3) of this section. In these circumstances,

MMS will notify you and give you an opportunity to provide written

information justifying your value.

(2) MMS may require you to certify that your arm's-length contract

provisions include all of the consideration the buyer pays, either

directly or indirectly, for the gas, residue gas, or gas plant product.

(c) If your gas, residue gas, or any gas plant product is not sold

under an arm's-length contract, then you must value the production

using the first applicable method as follows:

(1) The gross proceeds accruing to you under your non-arm's-length

contract sale (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). For residue gas or gas plant products, the

comparable arm's-length contracts must be for gas 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

will be considered: Price, time of execution, duration, market or

markets served, terms, quality of gas, residue gas, or gas plant

products, volume, and such other factors as may be appropriate to

reflect the value of the gas, residue gas, or gas plant products; or

(2) A value determined by consideration of other information

relevant in valuing like-quality gas, residue gas, or gas plant

products, including gross proceeds under arm's-length contracts for

like-quality gas in the same field or nearby fields or areas, or for

residue gas or gas plant products from the same gas plant or other

nearby processing plants. Other factors to consider include posted

prices for gas, residue gas, or gas plant products, prices received in

spot sales of gas, 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 gas,

residue gas, or gas plant products; or

(3) A net-back method or any other reasonable method to determine

value.

(d)(1) If you determine the value of production under paragraph (c)

of this section, you must retain all data relevant to the determination

of royalty value. Such data will be subject to review and audit, and

MMS will direct you to use a different value if it determines upon

review or audit that the value you reported is inconsistent with the

requirements of these regulations.

(2) You must make certain data available upon request to the

authorized MMS or Indian representatives, to the Office of the

Inspector General of the Department of the Interior, or other

authorized persons. You must make available your arm's-length sales and

volume data for like-quality gas, residue gas, and gas plant products

that are sold, purchased, or otherwise obtained from the same

processing plant or from nearby processing plants, or from the same or

nearby field or area.

(e) If MMS determines that you have not properly determined value,

you must pay the difference, if any, between royalty payments made

based upon the value you used and the royalty payments that are due

based upon the value MMS established. You also must pay interest

computed on that difference under 30 CFR 218.54. If you are entitled to

a credit, MMS will provide instructions how to take that credit.

(f) You may request a value determination from MMS. In that event,

you must propose to MMS a value determination method, and may use that

method in determining value for royalty purposes until MMS issues its

decision. You must submit all available data relevant to your proposal.

MMS will quickly determine the value based upon your proposal and any

additional

[[Page 49910]]

information MMS deems necessary. In making a value determination, MMS

may use any of the valuation criteria this subpart authorizes. That

determination will remain effective for the period stated therein.

After MMS issues its determination, you must make the adjustments in

accordance with paragraph (e) of this section. MMS will provide notice

of its decision to the Indian Tribes for their Tribal leases.

(g)(1) For gas, residue gas, and gas plant products valued under

this section, under no circumstances may the value of production for

royalty purposes be less than the gross proceeds accruing to the lessee

for gas, residue gas and/or any gas plant products, less applicable

transportation allowances and processing allowances determined under

this subpart.

(2) For gas plant products valued under this section and not valued

under Sec. 206.173, the alternative methodology for dual accounting,

the minimum value of production for each gas plant product is:

(i)(A) For production from leases in Colorado in the San Juan

Basin, New Mexico, and Texas, the monthly average minimum price

reported in commercial price bulletins for the gas plant product at

Mont Belvieu minus 8.0 cents per gallon.

(B) For production in Arizona, in Colorado outside the San Juan

Basin, Minnesota, Montana, North Dakota, Oklahoma, South Dakota, Utah,

and Wyoming, the monthly average minimum price reported in commercial

price bulletins for the gas plant product at Conway minus 7.0 cents per

gallon.

(ii) You may use any commercial price bulletin, but you must use

the same bulletin for all of the calendar year. If the commercial price

bulletin you are using stops publication, you may use a different

commercial price bulletin for the remaining part of the calendar year.

(iii) If you use a commercial price bulletin that is published

monthly, the monthly average minimum price is the bulletin's minimum

price. If you use a commercial price bulletin that is published weekly,

the monthly average minimum price is the arithmetic average of the

bulletin's weekly minimum prices. If you use a commercial price

bulletin that is published daily, the monthly average minimum price is

the arithmetic average of the bulletin's minimum prices for each

Wednesday in the month.

(h) You are required to place gas, residue gas and gas plant

products in marketable condition at no cost to the Indian lessor unless

otherwise provided in the lease agreement. When your gross proceeds

establish the value under this section, 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 your responsibility to place the gas, residue

gas, or gas plant products in marketable condition.

(i) For gas, residue gas, and gas plant products valued under this

section, 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 you fail to take proper or timely

action to receive prices or benefits to which you are entitled, you

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 you make timely

application for a price increase or benefit allowed under your contract

but the purchaser refuses, and you take reasonable measures, which are

documented, to force purchaser compliance, you will owe no additional

royalties unless or until monies or consideration resulting from the

price increase or additional benefits are received. This paragraph is

not intended to permit you to avoid your royalty payment obligation in

situations where your purchaser fails to pay, in whole or in part, or

timely, for a quantity of gas, 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 an MMS redetermination 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 and processing

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 laws

and regulations. All requests for information about determinations made

under this subpart must be submitted in accordance with the Freedom of

Information Act regulation of the Department of the Interior, 43 CFR

part 2.

(l) Time limitations on adjustments and audits for certain Indian

leases.

(1) If you determine the value of production under this section

from leases in Montana and North Dakota, you have time limits to make

adjustments to your reported royalty value. If you know of an

adjustment that would result in additional royalty owed, you are

required to report that adjustment and pay the additional royalty by

the time limit established in this paragraph. MMS also has time limits

to complete royalty audits for these leases only. There are exceptions

to these time limits in paragraph (l)(2) of this section.

(i) If your royalty valuation does not include a non-arm's-length

allowance under this subpart, you have until the last day of the 13th

month following the production month to report any adjustments on Form

MMS-2014. MMS must complete royalty audits timely and may not issue

demands or orders or initiate other action to collect royalty

underpayment for this production from the lessee after the last day of

the 12th month following the last day to make adjustments.

(ii) If your royalty valuation includes a non-arm's-length

allowance under this subpart, you have until the last day of the 9th

month following the month you submit to MMS your actual transportation

allowance report, or your actual processing allowance report, to report

any adjustments on Form MMS-2014. MMS must complete royalty audits

timely and may not issue demands or orders or initiate any other action

to collect royalty underpayments for this production from the lessee

after the last day of the 12th month after the last day to report

adjustments.

(2) Exceptions to the time limits in paragraph (l)(1) of this

section are:

(i) If you have a pending dispute with your purchaser, the time

periods to make adjustments in paragraphs (l)(1)(i) and (l)(1)(ii) of

this section will be extended for 6 months after your dispute is

finally resolved. The time period to complete audits and issue demands

or orders is correspondingly extended;

(ii) If you have a pending dispute with the person transporting or

processing your gas production, the time periods to make adjustments in

paragraphs (l)(1)(i) and (l)(1)(ii) of this section will be extended

for 6 months after your dispute is finally resolved. The time period to

complete audits and issue demands or orders is correspondingly

extended;

(iii) If there is a written agreement between you and MMS or its

delegee if applicable, the time period is extended for the period

stated in the agreement;

(iv) If there is a pending regulatory proceeding by any agency with

jurisdiction over sales prices for gas that

[[Page 49911]]

could affect the value of the gas, the time period to make adjustments

in paragraphs (l)(1)(i) and (l)(1)(ii) of this section will be extended

for 90 days after final resolution of the pending regulatory

proceeding, including any period for judicial review. The time period

to complete audits and issue demands or orders is correspondingly

extended;

(v) If the lessee fails or refuses to provide records or

information in its possession or control necessary to complete the

audit, the time period to issue demands or orders will be extended for

any time periods that MMS cannot obtain the records or information;

(vi) The time period in paragraphs (l)(1)(i) and (l)(1)(ii) of this

section will not apply in situations involving fraud or intentional

misrepresentation or concealment of a material fact for the purpose of

evading a payment obligation.

(3) For purposes of this paragraph (l), demand or order means an

order to pay a specific amount or an amount that the lessee easily may

calculate. It also includes an order to perform a restructured

accounting based upon repeated, systemic reporting errors for a

significant number of leases or a single lease for a significant number

of reporting months. The order to perform a restructured accounting

must specify the reasons and the factual bases for the order.

(4) If an audit discloses overpayments for any lease, the lessee

may credit those overpayments against any underpayments due on that

same lease.

Sec. 206.175 How to determine quantities and qualities of production

for computing royalties.

(a) For unprocessed gas, you must pay royalties on the quantity and

quality at the facility measurement point BLM either allowed or

approved.

(b) For residue gas and gas plant products, you must pay royalties

on your share of the monthly net output of the plant even though

residue gas and/or gas plant products may be in temporary storage.

(c) If you have no ownership interest in the processing plant and

you do not operate the plant, you may use the contract volume

allocation to determine your share of plant products.

(d) If you have an ownership interest in the plant or you operate

it, use the following procedure to determine the quantity of the

residue gas and gas plant products attributable to you for royalty

payment purposes:

(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 you must pay royalty is the net output of the

plant.

(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 non-uniform content,

the volumes of residue gas and gas plant products allocable to each

lease are based on theoretical volumes of residue gas and gas plant

products measured in the lease gas stream. You must calculate the

portion of net plant output of residue gas and gas plant products

attributable to each lease as follows:

(i) First, compute the theoretical volumes of residue gas and gas

plant products by multiplying the lease volume of the gas stream by the

tested residue gas content (mole percentage) or gas plant product (GPM)

content of the gas stream.

(ii) Second, calculate the theoretical volume of residue gas and

gas plant products delivered from all leases by summing the theoretical

volumes of residue gas and gas plant products delivered from each

lease.

(iii) Third, calculate the theoretical quantities of net plant

output of residue gas and gas plant products attributable to each lease

by multiplying the net plant output of residue gas and gas plant

products by the ratio of the theoretical volume of residue gas and gas

plant products delivered from all leases.

(4) You may request MMS approval of other methods for determining

the quantity of residue gas and gas plant products allocable to each

lease. If MMS approves a different method, it will be applicable to all

gas production from your Indian leases that is processed in the same

plant.

(e) You may not take any deductions from the royalty volume or

royalty value for actual or theoretical losses. Any actual loss of

unprocessed gas incurred prior to the facility measurement point will

not be subject to royalty if BLM determines that the loss was

unavoidable.

Sec. 206.176 How to do accounting for comparison.

(a) This section applies if you process your Indian lease gas and

that Indian lease requires accounting for comparison (also referred to

as actual dual accounting). Except as provided in paragraphs (b) and

(c) of this section, the actual dual accounting value, for royalty

purposes, is the greater of:

(1) The combined value of:

(i) The residue gas and gas plant products resulting from

processing the gas determined under either Sec. 206.172 or Sec. 206.174

of this subpart, including any applicable allowances; and

(ii) Any drip condensate associated with the processed gas

recovered downstream of the point of royalty settlement without

resorting to processing determined under Sec. 206.174 of this subpart,

including applicable allowances; or

(2) the value of the gas prior to processing determined under

either Sec. 206.172 or Sec. 206.174 of this subpart, including any

applicable allowances.

(b) If you are required to account for comparison, you may elect to

use the alternative dual accounting methodology provided for in

Sec. 206.173 of this subpart instead of the provisions in paragraph (a)

of this section.

(c) Accounting for comparison is not required for gas if no gas

from the lease is processed until after the gas flows into a pipeline

with an index located in an index zone. If you do not perform dual

accounting, you must certify to MMS that gas flows into such a pipeline

before it is processed.

(d) Except as provided in paragraph (e) of this section, if you

value any gas production from a lease for a month using the dual

accounting provisions of this section (including Sec. 206.173 of this

subpart), then the value of that gas is the minimum value for any other

gas production from that lease for that month flowing through the same

facility measurement point.

(e) If the weighted average Btu quality for your lease is less than

1,000 Btu's per cubic foot, see Sec. 206.173(b)(4)(ii) to determine if

you must perform a dual accounting calculation.

Sec. 206.177 General provisions regarding transportation allowances.

(a) When you value gas under Sec. 206.174 of this subpart at a

point off the lease (for example, sales point or point of value

determination), you may deduct from value a transportation allowance to

reflect the value, for royalty purposes, at the lease. The allowance is

based on the reasonable actual costs you incurred to transport

unprocessed gas, residue gas, or gas plant products from a lease to a

point off the lease. This would include, if appropriate, transportation

from the lease to a gas processing plant off the

[[Page 49912]]

lease and from the plant to a point away from the plant. You may not

deduct any allowance for gathering costs.

(b) You must allocate transportation costs among all products you

produce and transport as provided in Sec. 206.178 of this subpart.

(c)(1) Except as provided in paragraph (c)(2) of this section, your

transportation allowance deduction for each selling arrangement must

not exceed 50 percent of the value of the unprocessed gas, residue gas,

or gas plant product. For purposes of this section, natural gas liquids

are considered one product.

(2) If you ask MMS, it may approve a transportation allowance

deduction in excess of the limitations in paragraph (c)(1) of this

section. To receive this approval, you must demonstrate that the

transportation costs incurred in excess of the limitations in paragraph

(c)(1) of this section were reasonable, actual, and necessary. An

application for exception (using Form MMS-4393, Request to Exceed

Regulatory Allowance Limitation) must contain all relevant and

supporting documentation necessary for MMS to make a determination.

Under no circumstances may an allowance reduce the value for royalty

purposes under any selling arrangement to zero.

(d) If MMS conducts a review and/or audit and determines that you

have improperly determined a transportation allowance authorized by

this subpart, then you will be required to pay any additional

royalties, plus interest, determined in accordance with 30 CFR 218.54.

Alternatively, you may be entitled to a credit, but you will not

receive any interest on your overpayment.

Sec. 206.178 How to determine a transportation allowance.

(a) If you have an arm's-length transportation contract, the

provisions of this section explain how to determine your allowance.

(1)(i) If you have an arm's-length contract for transportation of

your production, the transportation allowance is the reasonable, actual

costs you incur for transporting the unprocessed gas, residue gas and/

or gas plant products under that contract. Paragraphs (a)(1)(ii) and

(a)(1)(iii) of this section provide a limited exception. You have the

burden of demonstrating that your contract is arm's-length. Your

allowances also are subject to paragraph (f) of this section. You are

required to submit to MMS a copy of your arm's-length transportation

contract(s) and all subsequent amendments to the contract(s) within 2

months of the date MMS receives your report which claims the allowance

on the Form MMS-2014.

(ii) When either MMS or a Tribe conducts reviews and audits, they

will examine whether or not the contract reflects more than the

consideration actually transferred either directly or indirectly from

you to the transporter for the transportation. If the contract reflects

more than the total consideration, then MMS may require that the

transportation allowance be determined under paragraph (b) of this

section.

(iii) If MMS determines that the consideration paid under an arm's-

length transportation contract does not reflect the value of the

transportation because of misconduct by or between the contracting

parties, or because you otherwise have breached your duty to the lessor

to market the production for the mutual benefit of you and the lessor,

then MMS will require that the transportation allowance be determined

under paragraph (b) of this section. In these circumstances, MMS will

notify you and give you an opportunity to provide written information

justifying your transportation costs.

(2)(i) If your arm's-length transportation contract includes more

than one product in a gaseous phase and the transportation costs

attributable to each product cannot be determined from the contract,

the total transportation costs must be allocated in a consistent and

equitable manner to each of the products transported. To make this

allocation, use the same proportion as the ratio of the volume of each

product (excluding waste products which have no value) to the volume of

all products in the gaseous phase (excluding waste products which have

no value). Except as provided in this paragraph, you cannot take an

allowance for the costs of transporting lease production which is not

royalty bearing without MMS approval, or without lessor approval on

Tribal leases.

(ii) As an alternative to paragraph (a)(2)(i) of this section, you

may propose to MMS a cost allocation method based on the values of the

products transported. MMS will approve the method if it determines

that:

(A) the methodology in paragraph (a)(2)(i) of this section cannot

be applied; or

(B) your proposal is more reasonable than the methodology in

paragraph (a)(2)(i) of this section.

(3)(i) If your arm's-length transportation contract includes both

gaseous and liquid products and the transportation costs attributable

to each cannot be determined from the contract, you must propose an

allocation procedure to MMS. You may use the transportation allowance

determined in accordance with your proposed allocation procedure until

MMS decides whether to accept your cost allocation.

(ii) You are required to submit all relevant data to support your

allocation proposal. MMS will then determine the gas transportation

allowance based upon your proposal and any additional information MMS

deems necessary.

(4) If your payments for transportation under an arm's-length

contract are not based on a dollar per unit, you must convert whatever

consideration is paid to a dollar value equivalent for the purposes of

this section.

(5) Where an arm's-length sales contract price or a posted price

includes a reduction for a transportation factor, MMS will not consider

the transportation factor to be a transportation allowance. You may use

the transportation factor to determine your gross proceeds for the sale

of the product. However, the transportation factor may not exceed 50

percent of the base price of the product without MMS approval.

(b) How to determine a transportation allowance if you have a non-

arm's-length or no contract. (1)(i) This paragraph applies where you

have a non-arm's-length transportation contract or no contract,

including those situations where you perform transportation services

for yourself. In these circumstances, the transportation allowance is

based upon your reasonable, allowable, actual costs for transportation

as provided in this paragraph.

(ii) All transportation allowances deducted under a non-arm's-

length or no contract situation are subject to monitoring, review,

audit, and adjustment. You must submit the actual cost information to

support the allowance to MMS on Form MMS-4295 within 3 months after the

end of the 12- month period to which the allowance applies. However,

MMS may approve a longer time period. MMS will monitor the allowance

deductions to ensure that deductions are reasonable and allowable. When

necessary or appropriate, MMS may require you to modify your actual

transportation allowance deduction.

(2) The transportation allowance for non-arm's-length or no-

contract situations is based upon your actual costs for transportation

during the reporting period. Allowable costs include operating and

maintenance expenses, overhead, and either depreciation and a return on

undepreciated capital investment (in accordance with paragraph

(b)(2)(iv)(A)

[[Page 49913]]

of this section), or a cost equal to the initial depreciable investment

in the transportation system multiplied by a rate of return in

accordance with paragraph (b)(2)(iv)(B) of this section. Allowable

capital costs are generally those costs for depreciable fixed assets

(including costs of delivery and installation of capital equipment)

which are an integral part of the transportation system.

(i) Allowable operating expenses include: Operations supervision

and engineering; operations labor; fuel; utilities; materials; ad

valorem property taxes; rent; supplies; and any other directly

allocable and attributable operating expense which you can document.

(ii) Allowable maintenance expenses include: Maintenance of the

transportation system; maintenance of equipment; maintenance labor; and

other directly allocable and attributable maintenance expenses which

you can document.

(iii) Overhead directly attributable and allocable to the operation

and maintenance of the transportation system is an allowable expense.

State and Federal income taxes and severance taxes and other fees,

including royalties, are not allowable expenses.

(iv) You may use either depreciation with a return on undepreciated

capital investment or a return on depreciable capital investment. After

you have elected to use either method for a transportation system, you

may not later elect to change to the other alternative without MMS

approval.

(A) To compute depreciation, you may elect to use either a

straight-line depreciation method based on the life of equipment or on

the life of the reserves which the transportation system services, or a

unit of production method. Once you make an election, you may not

change methods without MMS approval. A change in ownership of a

transportation system will not alter the depreciation schedule that the

original transporter/lessee established for purposes of the allowance

calculation. With or without a change in ownership, a transportation

system may be depreciated only once. Equipment may not be depreciated

below a reasonable salvage value. To compute a return on undepreciated

capital investment, you will multiply the undepreciated capital

investment in the transportation system by the rate of return

determined under paragraph (b)(2)(v) of this section.

(B) To compute a return on depreciable capital investment, you will

multiply the initial capital investment in the transportation system by

the rate of return determined under paragraph (b)(2)(v) of this

section. No allowance will be provided for depreciation. This

alternative will apply only to transportation facilities first placed

in service after March 1, 1988.

(v) The rate of return is the industrial rate associated with

Standard and Poor's BBB rating. The rate of return is the monthly

average rate as published in Standard and Poor's Bond Guide for the

first month of the reporting period for which the allowance is

applicable and is effective during the reporting period. The rate must

be redetermined at the beginning of each subsequent transportation

allowance reporting period which is determined under paragraph (4) of

this section.

(3)(i) The deduction for transportation costs must be determined

based on your cost of transporting each product through each individual

transportation system. If you transport more than one product in a

gaseous phase, the allocation of costs to each of the products

transported must be made in a consistent and equitable manner. The

allocation should be the same proportion as the ratio of the volume of

each product (excluding waste products which have no value) to the

volume of all products in the gaseous phase (excluding waste products

which have no value). Except as provided in this paragraph, you may not

take an allowance for transporting a product which is not royalty

bearing without MMS approval.

(ii) As an alternative to the requirements of paragraph (b)(3)(i)

of this section, you may propose to MMS a cost allocation method based

on the values of the products transported. MMS will approve the method

upon determining that:

(A) The methodology in paragraph (b)(3)(i) of this section cannot

be applied; or

(B) Your proposal is more reasonable than the method in paragraph

(b)(3)(i) of this section.

(4) Your transportation allowance under this paragraph (b) must be

determined based upon a calendar year or other period if you and MMS

agree to an alternative.

(5) If you transport both gaseous and liquid products through the

same transportation system, you must propose a cost allocation

procedure to MMS. You may use the transportation allowance determined

in accordance with your proposed allocation procedure until MMS issues

its determination on the acceptability of the cost allocation. You are

required to submit all relevant data to support your proposal. MMS will

then determine the transportation allowance based upon your proposal

and any additional information MMS deems necessary.

(c) Alternative transportation calculation. (1) As an alternative

to computing your transportation allowance under paragraph (b) of this

section, you may use as the transportation allowance 10 percent of your

gross proceeds but not to exceed 30 cents per MMBtu.

(2) Your election to use the alternative transportation allowance

calculation in paragraph (c)(1) of this section must be made at the

beginning of a month and must remain in effect for an entire calendar

year. When you first make the election, it will remain in effect until

the end of the succeeding calendar year, except for elections effective

January 1 which will be effective only for that calendar year.

(d) Reporting requirements. (1) If MMS requests, you must submit

all data used to determine your transportation allowance. The data must

be provided within a reasonable period of time that MMS will determine.

(2) You must report transportation allowances as a separate item on

Form MMS-2014. MMS may approve a different reporting procedure on

allottee leases, and with lessor approval on Tribal leases.

(e) Interest assessments if you claim a transportation allowance

that is too large. (1) If you report a transportation allowance which

results in an underpayment of royalties, you must pay late-payment

interest on the amount of that underpayment.

(2) The interest you are required to pay will be determined under

30 CFR 218.54.

(f) Adjustments. If for any month the actual transportation

allowance you are entitled to is less than the amount you took on Form

MMS-2014, you are required to report and pay additional royalties due

plus interest computed under 30 CFR 218.54, retroactive to the first

day of the first month you deducted the improper transportation

allowance. If the actual transportation allowance you are entitled to

is greater than the amount you took on Form MMS-2014 for any royalties

during the reporting period, you are entitled to a credit. No interest

will be paid on the overpayment.

(g) Actual or theoretical losses. If you are paying any

specifically identifiable actual or theoretical losses as part of your

arm's-length transportation contract, you may deduct those costs. In

all other circumstances you may not deduct those costs.

(h) Other transportation cost determinations. You must follow the

[[Page 49914]]

provisions of this section to determine transportation costs when

establishing value using either a net-back valuation procedure or any

other procedure that allows deduction of actual transportation costs.

Sec. 206.179 General provisions regarding processing allowances.

(a) When you value any gas plant product under Sec. 206.174 of this

subpart, you may deduct from value the reasonable actual costs of

processing.

(b) You must allocate processing costs among the gas plant

products. You must determine a separate processing allowance for each

gas plant product and processing plant relationship. Natural gas

liquids are considered as one product.

(c) The processing allowance deduction based on an individual

product may not exceed 66\2/3\ percent of the value of each gas plant

product determined under Sec. 206.174 of this subpart. Before you

calculate the 66\2/3\ percent limit, you must first reduce the value

for any transportation allowances related to post-processing

transportation authorized under Sec. 206.177 of this subpart.

(d) Processing cost deductions will not be allowed for placing

lease products in marketable condition. These costs include among

others, dehydration, separation, compression upstream of the facility

measurement point, or storage, even if those functions are performed

off the lease or at a processing plant. Costs for the removal of acid

gases, commonly referred to as sweetening, are not allowed for such

costs unless the acid gases removed are further processed into a gas

plant product. In such event, you will be eligible for a processing

allowance determined under this subpart. However, MMS will not grant

any processing allowance for processing lease production which is not

royalty bearing.

(e) You will be allowed a reasonable amount of residue gas 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 your residue

gas necessary for the operation of the processing plant will be allowed

royalty free.

(f) You do not owe royalty on residue gas, or any gas plant product

resulting from processing gas, which is reinjected into a reservoir

within the same lease, or agreement, until such time as those products

are finally produced from the reservoir for sale or other disposition

off-lease. This paragraph applies only when the reinjection is included

in a BLM-approved plan of development or operations.

(g) If MMS determines that you have determined an improper

processing allowance authorized by this subpart, then you will be

required to pay any additional royalties plus late-payment interest

determined under 30 CFR 218.54. Alternatively, you may be entitled to a

credit, but you will not receive any interest on your overpayment.

Sec. 206.180 How to determine an actual processing allowance.

(a) How to determine a processing allowance if you have an arms's-

length processing contract. The provisions of this paragraph explain

how you determine an allowance under an arm's-length processing

contract.

(1)(i) The processing allowance is the reasonable actual costs you

incur to process the gas under that contract. Paragraphs (a)(1)(ii) and

(a)(1)(iii) of this section provide a limited exception. You have the

burden of demonstrating that your contract is arm's-length. You are

required to submit to MMS a copy of your arm's-length contract(s) and

all subsequent amendments to the contract(s) within 2 months of the

date MMS receives your first report which deducts the allowance on the

Form MMS-2014.

(ii) When it conducts reviews and audits, MMS will examine whether

the contract reflects more than the consideration actually transferred

either directly or indirectly from you to the processor for the

processing. If the contract reflects more than the total consideration,

then MMS may require that the processing allowance be determined under

paragraph (b) of this section.

(iii) If MMS determines that the consideration paid under an arm's-

length processing contract does not reflect the value of the processing

because of misconduct by or between the contracting parties, or because

you otherwise have breached your duty to the lessor to market the

production for the mutual benefit of you and the lessor, then MMS will

require that the processing allowance be determined under paragraph (b)

of this section. In these circumstances, MMS will notify you and give

you an opportunity to provide written information justifying your

processing costs.

(2) If your arm's-length processing contract includes more than one

gas plant product and the processing costs attributable to each product

can be determined from the contract, then the processing costs for each

gas plant product must be determined in accordance with the contract.

You cannot take an allowance for the costs of processing lease

production which is not royalty-bearing.

(3) If your arm's-length processing contract includes more than one

gas plant product and the processing costs attributable to each product

cannot be determined from the contract, you must propose an allocation

procedure to MMS. You may use your proposed allocation procedure until

MMS issues its determination. You are required to submit all relevant

data to support your proposal. MMS will then determine the processing

allowance based upon your proposal and any additional information MMS

deems necessary. You cannot take a processing allowance for the costs

of processing lease production which is not royalty-bearing.

(4) If your payments for processing under an arm's-length contract

are not based on a dollar per unit, you must convert whatever

consideration is paid to a dollar value equivalent for the purposes of

this section.

(b) How to determine a processing allowance if you have a non-

arm's-length or no contract. (1)(i) This paragraph applies if you have

a non-arm's-length processing contract or have no contract, including

those situations where you perform processing for yourself. In these

circumstances the processing allowance is based upon your reasonable

actual costs for processing as provided in paragraph (b) of this

section.

(ii) All processing allowances deducted under a non-arm's-length or

no-contract situation are subject to monitoring, review, audit, and

adjustment. You must submit the actual cost information to support the

allowance to MMS on Form MMS-4109 within 3 months after the end of the

12-month period for which the allowance applies. MMS may approve a

longer time period. MMS will monitor the allowance deduction to ensure

that deductions are reasonable and allowable. When necessary or

appropriate, MMS may require you to modify your actual processing

allowance.

(2) The processing allowance for non-arm's-length or no-contract

situations is based upon your actual costs for processing during the

reporting period. Allowable costs include operating and maintenance

expenses, overhead, and either depreciation and a return on

undepreciated capital investment (in accordance with paragraph

(b)(2)(iv)(A) of this section), or a cost equal to the

[[Page 49915]]

initial depreciable investment in the processing plant multiplied by a

rate of return in accordance with paragraph (b)(2)(iv)(B) of this

section. Allowable capital costs are generally those costs for

depreciable fixed assets (including costs of delivery and installation

of capital equipment) which are an integral part of the processing

plant.

(i) Allowable operating expenses include: Operations supervision

and engineering; operations labor; fuel; utilities; materials; ad

valorem property taxes; rent; supplies; and any other directly

allocable and attributable operating expense which the lessee can

document.

(ii) Allowable maintenance expenses include: maintenance of the

processing plant; maintenance of equipment; maintenance labor; and

other directly allocable and attributable maintenance expenses which

you can document.

(iii) Overhead directly attributable and allocable to the operation

and maintenance of the processing plant is an allowable expense. State

and Federal income taxes and severance taxes, including royalties, are

not allowable expenses.

(iv) You may use either depreciation with a return on undepreciable

capital investment or a return on depreciable capital investment. After

you elect to use either method for a processing plant, you may not

later elect to change to the other alternative without MMS approval.

(A) To compute depreciation, you may elect to use either a

straight-line depreciation method based on the life of equipment or on

the life of the reserves which the processing plant services, or a

unit-of-production method. Once you make an election, you may not

change methods without MMS approval. A change in ownership of a

processing plant will not alter the depreciation schedule that the

original processor/lessee established for purposes of the allowance

calculation. However, for processing plants you or your affiliate

purchase that do not have a previously claimed MMS depreciation

schedule, you may treat the processing plant as a newly installed

facility for depreciation purposes. With or without a change in

ownership, a processing plant may be depreciated only once. Equipment

may not be depreciated below a reasonable salvage value. To compute a

return on undepreciated capital investment, you will multiply the

undepreciable capital investment in the processing plant by the rate of

return determined under paragraph (b)(2)(v) of this section.

(B) To compute a return on depreciable capital investment, you will

multiply the initial capital investment in the processing plant by the

rate of return determined under paragraph (b)(2)(v) of this section. No

allowance will be provided for depreciation. This alternative will

apply only to plants first placed in service after March 1, 1988.

(v) The rate of return is the industrial rate associated with

Standard and Poor's BBB rating. The rate of return is the monthly

average rate as published in Standard and Poor's Bond Guide for the

first month for which the allowance is applicable. The rate must be

redetermined at the beginning of each subsequent calendar year.

(3) Your processing allowance under this paragraph (b) must be

determined based upon a calendar year or other period if you and MMS

agree to an alternative.

(4) The processing allowance for each gas plant product must be

determined based on your reasonable and actual cost of processing the

gas. You must base your allocation of costs to each gas plant product

upon generally accepted accounting principles. You can not take an

allowance for the costs of processing lease production which is not

royalty-bearing.

(c) Reporting.

(1) If MMS requests, you must submit all data used to determine

your processing allowance. The data must be provided within a

reasonable period of time, as MMS determines.

(2) You must report gas processing allowances as a separate item on

the Form MMS-2014. MMS may approve a different reporting procedure for

allottee leases, and with lessor approval on Tribal leases.

(d) Interest assessments if you claim a processing allowance that

is too large. (1) If you report a processing allowance which results in

an underpayment of royalties, you must pay interest on the amount of

that underpayment.

(2) The interest you are required to pay will be determined in

accordance with 30 CFR 218.54.

(e) Adjustments. (1) If for any month the actual gas processing

allowance you are entitled to is less than the amount you took on Form

MMS-2014, you are required to pay additional royalties plus interest

computed under 30 CFR 218.54, retroactive to the first day of the first

month you deducted a processing allowance. If the actual processing

allowance you are entitled is greater than the amount you took on Form

MMS-2014, you are entitled to a credit. However, no interest will be

paid on the overpayment.

(f) Other processing cost determinations. You must follow the

provisions of this section to determine processing costs when

establishing value using either a net-back valuation procedure or any

other procedure that requires deduction of actual processing costs.

Sec. 206.181 Processing allowances for use in certain dual accounting

situations.

(a) Where accounting for comparison (dual accounting) is required

for gas production from a lease but you or someone on your b

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