[Federal Register Volume 61, Number 185 (Monday, September 23, 1996)]
[Proposed Rules]
[Pages 49894-49917]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 96-23924]



[[Page 49893]]


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Part V





Department of the Interior





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Minerals Management Service



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30 CFR Parts 202 and 206



Amendments to Gas Valuation Regulations for Indian Leases; Proposed 
Rule

  Federal Register / Vol. 61, No. 185 / Monday, September 23, 1996 / 
Proposed Rules  

[[Page 49894]]



DEPARTMENT OF THE INTERIOR

Minerals Management Service

30 CFR Parts 202 and 206

RIN 1010-AB57


Amendments to Gas Valuation Regulations for Indian Leases

AGENCY: Minerals Management Service, Interior.

ACTION: Notice of proposed rulemaking.

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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 behalf does 
not process the gas, and you have elected to perform actual dual 
accounting under Sec. 206.176 of this subpart, you must use the first 
applicable method as follows to establish processing costs for dual 
accounting purposes:
    (1) The average of the costs established in your current arm's-
length processing agreements for gas from the lease, provided that some 
gas has previously been processed under these agreements; or
    (2) The average of the costs established in your current arm's-
length processing agreements for gas from the lease, provided that the 
agreements are in effect for plants to which the lease is physically 
connected and under which gas from other leases in the field or area is 
being or has been processed; or
    (3) A proposed comparable processing fee submitted to either the 
Tribe and MMS (for tribal leases) or MMS (for allotted leases) with 
your supporting documentation submitted to MMS. If MMS does not take 
action on your proposal within 120 days, the proposal will be deemed to 
be denied and subject to appeal to the MMS Director under 30 CFR part 
290; or
    (4) Processing costs based on the regulations in Sec. 206.179 and 
Sec. 206.180 of this subpart.

    Note: Forms are published for comments only and will not be 
codified in the CFR.

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[FR Doc. 96-23924 Filed 9-20-96; 8:45 am]
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