Amendments to Gas Valuation Regulations for Indian Leases

SUMMARY: The Minerals Management Service (MMS) is amending its

regulations governing the valuation for royalty purposes of natural gas

produced from Indian leases. These changes add alternative valuation

methods to the existing regulations to ensure that Indian lessors

receive maximum revenues from their mineral resources as required by

the unique terms of Indian leases and MMS's trust responsibility to the

Indian lessor. Further, these changes will improve the accuracy of

royalty payments at the time the royalties are due.

DATES: The effective date of this final rule is January 1, 2000.

ADDRESSES: David S. Guzy, Chief, Rules and Publications Staff, Minerals

Management Service, Royalty Management Program, PO Box 25165, MS 3021,

Denver, Colorado 80225. Courier address is Building 85, Denver Federal

Center, Denver, Colorado 80225. E-mail address is RMP.[email protected].

FOR FURTHER INFORMATION CONTACT: David S. Guzy, Chief, Rules and

Publications Staff; phone (303) 231-3432; fax (303) 231-3385; e-mail

[email protected].

SUPPLEMENTARY INFORMATION: The principal authors of this final rule are

Donald T. Sant and Richard Adamski of the Royalty Management Program,

MMS, and Peter Schaumberg of the Office of the Solicitor, Department of

the Interior.

I. Background

MMS's purposes in revising the current regulations regarding the

valuation of gas production from Indian leases are:

(1) To ensure that Indian mineral lessors receive the maximum

revenues from mineral resources on their land consistent with the

Secretary of the Interior's (Secretary) trust responsibility and lease

terms; and

(2) To improve the regulatory framework so that information is

available which would permit lessees to comply with the regulatory

requirements at the time that royalties are due.

II. Comments on Proposed Rule

On September 23, 1996, MMS published a notice of proposed

rulemaking (61 FR 49894) to amend the valuation regulations for gas

production from Indian leases. The framework for the proposed rule was

the product of an Indian Gas Valuation Negotiated Rulemaking Committee

(the Committee). The proposed rulemaking provided for a 60-day comment

period, which ended November 22, 1996, and was extended to December 3,

1996 (61 FR 59849, November 25, 1996). During the public comment

period, MMS received 13 written comments: seven responses from

industry, four from industry trade groups or associations, one from an

Indian tribe, and one from an Indian agency. A public hearing was held

in Oklahoma City, Oklahoma, on October 23, 1996. MMS reopened the

public comment period until April 4, 1997 (62 FR 10247, March 6, 1997)

to receive comments on the issue of proceeds received from contract

settlements. Two comments were received: one from industry and one from

an industry trade association.

MMS has considered carefully all of the public comments received

during this rulemaking. MMS hereby adopts final regulations governing

the valuation of gas produced from Indian leases. These regulations

will apply prospectively to gas produced on or after the effective date

specified in the DATES section of this preamble.

This final rule reflects certain changes to the proposed rule.

However, none of these changes are significant in that they affect the

basic structure or approach of the new gas valuation rules.

General Comments

All commenters endorsed the concept of revising the existing

regulations to provide simplicity and certainty, decrease

administrative costs, and decrease litigation. Industry generally

supports the use of independent published index prices for valuing gas

produced from Indian leases. Industry also supports the concept of an

alternative ``percentage increase'' to satisfy the dual accounting

requirement contained in most Indian leases to the extent the lessee

chooses to use this alternative methodology voluntarily. Industry

objects to the following parts of the proposed rule:

The safety net concept for nondedicated sales.

The separate dual accounting requirement on natural gas

liquids.

The gross proceeds requirement if gas production was

subject to a previous contract that was part of a gas contract

settlement.

The Rocky Mountain Oil and Gas Association (RMOGA) states in its

comments that ``it believes the inclusion of a safety net provision is

a profound violation of the original consensus on gross proceeds and

major portion lease requirements.'' RMOGA also states that ``Indeed,

the concept of a safety net was not raised until many months after the

vote on the formula had been taken.'' The Independent Petroleum

Association of Mountain States (IPAMS) also objects to ``the belated

introduction of the ``safety net'' requirement which, as discussed in

more detail below, undermines the compromise that was reached on the

major portion index value and dual accounting formulae.'' The Council

of Petroleum Accountants Societies (COPAS) states ``The COPAS

representative on the Committee voted in favor of the original index-

based formula at the Committee's May 1995 meeting based on the belief

that the use of that formula would satisfy both the gross proceeds and

major portion clauses contained in most Indian leases, with the

exception of gas sold under certain high-priced dedicated contracts.

The record will show that this was clearly the focus of the Committee's

discussions leading up to the vote, and that the prospect of a ``safety

net'' for nondedicated contracts was not raised until several months

later, and came as a surprise to the industry members.''

Response. A review of the record generally contradicts these

comments. The first formal proposals for valuation of gas production

using index formulas were made at the April 12-13, 1995, meeting of the

Committee. The proposal of the Federal Government members was patterned

after the Federal Gas Valuation Negotiated Rulemaking Committee

proposal (Final Report, March 1995) and included an analysis of gross

proceeds for sales before the index point to ensure the validity of

index-based values. The proposal offered by the Indian representatives

included the concept of a safety net. The proposal to be taken back to

the committee members' constituents, dated April 13, 1995, 2:45 p.m.

version, stated that ``a safety net must be developed to protect the

Indian lessor in certain circumstances.''

The meeting notes for the June 14-15, 1995, meeting at which the

index formula was adopted included, under the ``safety net'' heading:

``big discussion as to what to compare to the formula value. Is it the

amount accruing

[[Page 43507]]

to the lessee (because we do not want to use the term gross

proceeds)?'' A subgroup was formed at the July 12-13, 1995, meeting to

bring safety net options to the next meeting. A second subgroup was

formed at the August 8-10, 1995, meeting to further analyze the options

for the safety net. The options these subgroups developed all had some

concept of obtaining additional royalty for high-value sales beyond the

index-pricing point or of gathering data to validate the index. The

safety net was voted on and approved at the next meeting on October 17-

19, 1995.

Certainly, the group may have adopted a different proposal had

different dynamics occurred within the group or a different sequence of

events occurred. But the proposed safety net was a product of the

decisions the Committee made.

MMS and the one Indian commenter believe that the safety net is an

essential part of the proposed rule, and MMS will retain the safety net

in the final rule. The Indian comment aptly summarizes the issue: ``The

once-a-year calculation of a safety net price is a small concession by

Indian lessees to accomplish certainty and to foster general confidence

in the validity of the published index prices. The calculation of the

safety net price does not require a detailed ``tracing'' of molecules

produced from all Indian leases to all distant sales points.'' In

addition, the regulation permits only 1 year for MMS to verify a

lessee's safety net calculation. There should not be a continuation of

audit disputes and litigation over the safety net or problems in

administering it.

MMS agrees that the gross proceeds requirement in the proposed rule

dealing with the issue of gas contract settlements changed the

Committee's agreement that the index formula was to replace both the

gross proceeds requirement and the major portion requirement. The

comment period was specifically reopened to address this issue. Only

two comments were received. In addition, courts in two different

circuits have issued decisions in gas contract settlements cases during

and after the comment period, as explained more fully below, that

affect the handling of the gas contract settlements issue in this rule.

This final rule includes the concept that some contract settlement

proceeds are royalty bearing, as explained below, but does not require

a monthly gross proceeds comparison to the index formula. Those

contract settlement proceeds that are royalty-bearing will be part of

gross proceeds when value is determined by gross proceeds. Examples

include production under a dedicated contract and gas produced in

nonindex areas where the initial value is determined by gross proceeds.

For index areas, MMS will require the gross proceeds for gas sold under

nondedicated contracts to be calculated only if the contract settlement

proceeds per MMBtu, when added to 80 percent of the safety net price,

exceed the index formula value for the month, including any increase

for dual accounting. This computation would be made after the safety

net prices were reported to MMS by the lessee.

After publication of the final rule, MMS plans to hold training

sessions with industry to illustrate the various procedures for

computing value under this rule.

Specific Comments and Other Principal Changes to the Proposed Rule

Comment on Sec. 202.550(a)(1)--now Sec. 202.550(b). MMS received

five comments on this issue. The commenters did not object to the tribe

rather than MMS deciding when the lessor would take gas as royalty in

kind as long as the Indian lessor was subject to the same rules of

notification with which MMS must comply.

Response. The tribe will abide by the terms of notification in the

lease. No change is made in the final rule.

Comment on Sec. 202.550(a)(2)--now Sec. 202.550(d). MMS

specifically requested comment on whether the Department should

continue to approve requests for royalty rate reductions on allotted

leases when a lessee demonstrates economic hardship. Twelve commenters

believe that MMS should continue to provide this approval because of

the difficulty in identifying and locating allottee lessors. Two

commenters believe that the lease language and the language in 25

U.S.C. 396 do not expressly allow the Secretary to approve a reduction

without full consent of every lessor.

Response. MMS agrees that under current law the Secretary may not

approve royalty rate reductions without full consent. No change is made

in the final rule.

Comment on Sec. 202.550(b)--now Sec. 202.551. Four commenters

supported the concept that you should pay royalties on your entitled

share of gas production from Indian leases not in approved Federal unit

or communitization agreements rather than on your actual takes.

Response. MMS disagrees and we changed the final rule to require

royalties on your actual takes for leases not in an approved Federal

agreement (AFA). This is consistent with the requirement for Federal

leases under the Royalty Simplification and Fairness Act of 1996 (Pub.

L. 104-185, as corrected by Pub. L. 104-200). If another person takes

some of your entitled share but does not pay for the royalties owed,

you are liable for those royalties.

Comment on Sec. 202.550(d)--now Sec. 202.555. Five commenters

stated that transportation field fuel and reinjected unprocessed gas,

gas plant products, and residue should also be listed as gas not

subject to royalty.

Response. Any production that is reinjected and is not produced

from the lease, is not subject to royalty until it is again produced

and removed from the lease. Transportation field fuel is subject to the

requirements of the regulation. We do not believe the suggested change

is necessary.

Structure changes to part 202. In an effort to make the final rule

easier to read, we restructured Sec. 202.550 to create more sections

with headings. Also, we made some changes to clarify the regulatory

provisions in this part. None of these changes were intended to change

the principal intent of the rule.

One change was made to proposed Sec. 202.550(b), now Sec. 202.551.

This section explains the volumes for which you must pay royalties for

leases not committed to an approved Federal unit or communitization

agreement. Under this section you are liable for royalties on your

entitled share of production. Thus, if you hold 40 percent of the

operating rights, you are liable for 40 percent of the royalties.

However, under this section you must report and pay royalties based on

your takes. So if you take 30 percent of the gas production, you must

report and pay on that volume. The same applies if you take 50 percent.

To address concerns about liability for volumes not taken, we added a

new provision to this section so that all interest owners for the lease

may ask MMS for permission to report and pay on entitlements. If MMS

grants the request, it will provide valuation instructions consistent

with the provisions in part 202 for over-taken and under-taken volumes.

See the new Secs. 202.552, 202.553, and 202.554 (proposed

Sec. 202.550(c)) which explain how to value over-taken and under-taken

volumes for leases in approved Federal unit or communitization

agreements. MMS will apply a similar approach for stand-alone leases.

Comment on Sec. 206.170(c). Eleven commenters believe that the

lessee and tribal lessor should be allowed to negotiate alternate

valuation methods

[[Page 43508]]

on their own without MMS approval. The commenters agree that MMS should

be part of the negotiation process between lessees and allottees.

Response. MMS is confident that tribes can negotiate independently

with lessees. Consistent with the Secretary's trust responsibility, MMS

will review and approve agreements for alternate valuation

methodologies that are negotiated by the tribe and do not breach the

trust responsibility of the Secretary. MMS will take a more active role

in negotiations between lessees and allottee lessors. MMS does not

believe it is necessary to change the language in the final rule.

Comment on Sec. 206.171. Ten commenters recommend that the

definition of ``marketing affiliate'' be reinstated in the final rule.

Two commenters noted that in the definition of ``posted price'' it is

unnecessary and misleading to refer to marketable condition. They state

that gas, in a publicly available price bulletin, is by definition in

marketable condition.

Response. We know of no company that meets the requirements of the

regulatory definition of ``marketing affiliate'' at 30 CFR 206.171. MMS

did not include the definition in the final rule. MMS agrees that the

definition of ``posted price'' is unnecessary and has removed the

definition in the final rule. MMS has also removed references to

``posted price'' under the benchmarks at Sec. 206.174(c)(2) and the

transportation factor under Sec. 206.178(a)(5).

Comment on Sec. 206.172. One commenter listed the following

concerns:

How would a publication become approved?

Response. Publications will be approved if they meet MMS's

criteria, which are listed under Sec. 206.172(d)(4).

What kind of market condition changes will be considered

to require a Technical Conference for disqualifying an index zone?

Response. MMS will closely monitor the market sales prices realized

in the short and long-term markets. If it appears that index-based

values no longer represent reasonable values obtained in the entire

market, then MMS will convene a Technical Conference.

How often will MMS publish the list of acceptable

publications in the Federal Register?

Response. We plan to update the list of acceptable publications

whenever we need to add a new publication or we need to drop a current

publication.

How will independent payors who do not receive the Federal

Register be notified?

Response. MMS will make sure that all payors are notified through

periodic ``Dear Payor Letters'' and publication of those letters on the

Internet.

Which tables within the publications will be used and can

they vary from month to month?

Response. When MMS publishes the list of acceptable publications,

we will be very specific as to the proper tables and pipelines within

the publications you should use in computing the index-based formula

price.

How will MMS determine that the published price does not

reflect value accurately?

Response. MMS will closely monitor published prices and compare

them to prices published in other publications and to prices received

in the entire gas market. MMS will investigate price changes.

Does this mean each payor will have to subscribe to all

MMS-approved publications?

Response. No, MMS will calculate the index-based formula price for

each index zone on a monthly basis and provide this information to all

interested payors.

Why is a safety net price required if rates have been

accepted by MMS previously?

Response. The safety net price is intended to capture the

significantly higher values for sales occurring beyond the index point.

Comment on Sec. 206.172(b)(1)(ii). Two commenters recommended that

this paragraph be modified to refer to gas that is not processed before

it flows into a mainline and should not be limited to pipelines with an

index point.

Response. The Committee spent time discussing the best way to

describe when and where gas is or is not processed. The Committee

believed the term ``mainline'' was not used consistently throughout the

industry. MMS will change Sec. 206.176 of this title to state that dual

accounting is not required if gas is not processed before it flows into

a mainline pipeline for nonindex areas. MMS believes that for index

areas the language of the proposed rule is the proper terminology. We

did not define ``mainline'' but intend to have the same characteristics

as a pipeline in an index zone with an index.

Comment on Sec. 206.172(b)(2)(ii)--now 206.172(b)(2). Twelve

commenters objected to the inclusion of the contract settlement

provision in the proposed rule because in addition to the index-based

value calculation, it would require a gross proceeds calculation. The

same commenters stated that the Committee did not agree to include gas

contract settlement language and recommended that this paragraph be

deleted. One commenter supported the inclusion of gas contract

settlement language because of the position that royalty is due, at a

minimum, on all the components of a lessee's gross proceeds.

Response. The Committee was unable to reach consensus on the issue

of contract settlements. The Committee spent considerable time

discussing whether contract settlement amounts should be included in

the safety net calculation. The Committee agreed to language in the

proposed rule which would exclude contract settlement amounts from the

safety net value and agreed to address the issue in 30 CFR 206.172 of

the proposed rule.

MMS acknowledges that the issue of royalty on contract settlement

proceeds is currently in litigation. Under judicial decisions issued as

of the time of this rule, some contract settlement payments are or may

be royalty-bearing while others are not. The final rule includes

contract settlement amounts as part of royalty value only when value is

determined by gross proceeds and only when the contract settlement

payment is of the type that is royalty-bearing as a part of gross

proceeds. Value is determined by gross proceeds when valuing production

sold under dedicated contracts or the initial value in nonindex areas.

For nondedicated contracts, gross proceeds will only need to be

calculated when the safety net price plus the royalty-bearing contract

settlement proceeds increment exceeds the index formula value including

the dual accounting increase. We will modify the current policy

whenever necessary to conform with the outcome of ongoing litigation.

This rule does not change which contract settlement payments are

royalty-bearing or to what extent a particular payment is royalty-

bearing. If and to the extent that a particular contract settlement

payment would be royalty-bearing as part of the lessee's gross proceeds

before this rule, it is royalty-bearing under this rule when value is

determined by gross proceeds. If a contract settlement payment is not

royalty-bearing before this rule, it likewise has no royalty

consequence under this rule.

In Mobil Exploration and Producing U.S. Inc. (MMS-94-0151-OCS, May

4, 1998), the Department determined that contract settlement payments

to buy out of the terms of a gas contract and

[[Page 43509]]

terminate the sales relationship entirely are not royalty-bearing. It

also determined that payments to compromise Mobil's purchaser's

liability for accrued but unpaid take-or-pay liabilities were not

royalty-bearing.

In United States v. Century Offshore Management Corp., 111 F.3d 443

(6th Cir., 1997), the Sixth Circuit Court of Appeals concluded that MMS

could collect royalties on what MMS had identified as a ``buydown''

payment.

Comment on Sec. 206.172(c)(1) and (2). Two commenters suggested

that these paragraphs should make it clear that both transportation and

processing allowances are used in dual accounting. These same

commenters stated that the reference in paragraph (c)(2)(iii) to

subpart B of this part should be more specific.

Response. We have included ``and/or transportation allowances'' in

Sec. 206.172(c)(2)(ii). The reference to the entire subpart B of this

part is necessary so that drip condensate may be valued correctly under

various sale scenarios.

Comment on Sec. 206.172(d) (1) through (6). One commenter stated

that the index-based valuation formula accomplished the Committee's

goals of availability, timeliness, and satisfying the Indian lease

language. One commenter believed that the 10 percent reduction to the

index-based value may be considerably lower than actual transportation

prices. This commenter suggests the reduction should be between 15 and

20 percent. Five commenters recommended that MMS should clarify in

Sec. 206.172(d)(6) that individual index prices will be excluded if MMS

determines the index price does not accurately reflect the value of

production in that index zone ``on a prospective basis only.''

Response. The 10 percent reduction to the index-based value was a

compromise reached by the Committee to reflect average transportation

costs. MMS believes that this percentage combined with the

administrative savings realized by not having to file forms and track

actual costs should adequately compensate the lessee in most cases. MMS

believes that Sec. 206.172(d)(6) makes clear our intent to exclude an

individual index price only after notification by publication in the

Federal Register. We do not believe the suggested change adds to or

clarifies the sentence.

Comment on Sec. 206.172(e). One commenter stated that the safety

net comparison of values is absolutely essential for the protection of

the Indian lessor and for the validation of the published index price

ranges. Twelve commenters strenuously object to inclusion of a ``safety

net'' for the following reasons:

(1) The index-based formula will yield a value that is far in

excess of market value. This formula price should satisfy the gross

proceeds and major portion clauses of an Indian lease without any need

for a ``safety net'' on nondedicated sales.

(2) The safety net provision, to tie value to markets downstream of

an index point, implies a duty to market even further from the field or

area.

(3) The concept of a safety net was not raised until many months

after the vote on the formula had been taken.

(4) The certainty, simplicity, and any administrative benefits

gained from the use of the index-based valuation formula are negated

with the safety net.

(5) The safety net provision would require tracing gas, and would

inevitably lead to a continuation of the current cycle of endless audit

disputes and litigation with regard to gas valuation on Indian leases.

Response. The comment that the idea of a safety net was not raised

until many months after the vote on the index-based formula was taken

is inaccurate. As discussed above, a review of the Committee's meeting

minutes for April 1995 indicates that the concept of some type of

safety net was part of the original valuation proposal from the Indian

representatives and part of the original draft of the index-based

formula. The safety net was conceived as a comparison of the index-

based value to some other value that would represent the actual

proceeds accruing to the lessee. In June 1995, the Committee voted on

and adopted the index-based formula. The safety net provision, although

part of the proposal, had not yet been discussed in detail by the

Committee. A subgroup composed of industry, Indian, and Federal

representatives was formed in July 1995 to explore the safety net

issue. The Committee continued to periodically discuss the safety net

issue over the next year and voted in October 1995 to include a safety

net in the proposed rule and finally adopted the language that is

contained in the proposed rule in May 1996.

The safety net, by comparing index prices to prices that reflect

sales made beyond an index point, ensures that the index-based value

represents the value of all market transactions. The safety net is

calculated using prices received for gas sold downstream of the index

point. The lessee includes only sales under those contracts that

establish a delivery point beyond the first index-pricing point to

which the gas flows. It includes only the lessee's or its affiliate's

sales prices, and it does not require detailed calculations for the

costs of transportation. The safety net price captures the

significantly higher values for sales occurring beyond the index point.

Although the safety net requires tracing the gas beyond the index-

pricing point, confidentiality should not be an issue because only the

lessee's and its affiliate's sales prices are used in the volume

weighted average calculation. MMS has added ``or your affiliate's'' at

Sec. 206.172(e)(3) to make it clear it is either the lessee's or its

affiliate's arm's-length sales contract that is used in the safety net.

MMS has only 1 year from the date the lessee's safety net prices on

Form MMS-4411, Safety Net Report, are due to order the lessee to amend

its safety net price calculation. If MMS does not order any adjustment,

then the safety net price is final. This provides certainty to the

lessee and alleviates extended audit disputes. MMS has determined that

the safety net is necessary to ensure that Indian lessors receive

royalties on the proper value of production as discussed above.

MMS has added at Sec. 206.172(e)(4)(i) that 80 percent of the

safety net value minus 125 percent of the index formula value is the

safety net differential.

MMS has revised Sec. 206.172(e)(4)(ii) to clarify that additional

royalty is due if the safety net differential under

Sec. 206.172(e)(4)(i) is a positive number. The proposed rule did not

include a multiplication by any lease royalty rates. In the final rule,

paragraph (e)(5)(i) identifies the Indian leases which had production

that was sold beyond the index-pricing point and multiplies the

production by the safety net differential and by the royalty rate in

the lease. Paragraph (e)(5)(ii) describes how you allocate production

to Indian leases when production has been commingled with non-Indian

production and then sold beyond the first index pricing point.

Comment on Sec. 206.173. Nine commenters supported the use of the

alternative methodology for dual accounting, if its use is optional.

Two commenters stated that Sec. 206.173(a)(2)(iii) of this title is

grammatically incorrect and should be revised to read: ``When you elect

to use the alternative methodology for a designated area, you must also

use the alternative methodology for any new wells commenced and any new

leases acquired in the designated area during the term of the

election.''

[[Page 43510]]

Response. We agree with the comment and made the suggested wording

change to Sec. 206.173(a)(2)(iii) in the final rule.

Also, Sec. 206.173(b)(4) is modified to read ``if any of your gas

from the lease is processed during a month'' instead of ``if you

process any gas from the lease'' to make it clear that dual accounting

is required for all lease production if any of your production is

processed, not just for the gas production you process from your Indian

lease.

The last sentence of Sec. 206.174(a)(1) was changed to make it

clear that a separate major portion calculation other than the index

value is not required for leases in an index zone with dedicated

contracts.

Comment on Sec. 206.174(a)(4)(ii)--now 206.174(a)(4)(iii). Five

commenters suggested that MMS include in the final rule a process by

which industry may contest MMS's major portion calculation. These same

commenters recommended insertion of the phrase ``less applicable

allowances'' after the phrase ``Form MMS-2014'' in the first sentence

to clarify that allowances will be deducted before the major portion

price is calculated.

Response. A lessee or Indian lessor may appeal the major portion

value under 30 CFR part 290. MMS will calculate the major portion value

using values from Form MMS-2014, Report of Sales and Royalty

Remittance, which have been reduced by applicable transportation

allowances. MMS does not agree that the suggested wording change is

clarifying or necessary.

Comment on Sec. 206.174(g)(2). One commenter suggested that the

final rule require that the minimum value for gas plant products be

based on the highest price, or at the very least, the average of the

highest prices found in commercial price bulletins. Twelve commenters

believe that the ``minimum value'' for gas plant products would

effectively establish a dual accounting requirement for liquids values

within the dual accounting calculation, and a major portion requirement

on liquids within the major portion calculation, neither of which is

required or even suggested by the lease terms. These same twelve

commenters believed that the index-based formula would satisfy the

gross proceeds and major portion requirements for the entire gas

stream. One commenter stated that prices published in one of the

publications MMS suggested are not available until 90 days after

production. This would make timely reporting of gas plant product

values impossible. Twelve commenters responded to MMS's request for

comments on several specific issues as follows:

Is a minimum value needed when a lessee chooses the actual

dual accounting methodology?

Comment. No. It was demonstrated during the review of the

percentage dual accounting alternative that liquid valuation was not a

significant factor in the calculation.

Are there other better methods to use?

Comment. No. No method is preferable to any other because the

concept of a minimum value for gas plant products is objectionable.

Are Conway and Mont Belvieu the proper locations to look

for prices for gas plant products?

Comment. Eleven commenters stated that the proper location to look

for gas plant products values is the point at which the products are

sold. This would be consistent with the lease language which refers to

the field or area. One commenter stated that if MMS is looking for some

form of gas plant liquid postings, then it should look to the locations

of those postings.

Are the 7.0 and 8.0 cents per gallon the right deductions

for transportation and fractionation?

Comment. Eleven commenters found this question irrelevant because

the entire concept is objectionable. One commenter stated that the

deductions appear reasonable for Conway and Mount Belvieu price

postings.

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

better deduction?

Comment. Eleven commenters found this question irrelevant because

the entire concept is objectionable. One commenter stated that a

percentage might provide more certainty but that may be difficult to

develop because of price fluctuations.

Response. The Indian lease terms require that ``value'' be

calculated based on the highest price paid or offered for the major

portion of oil, gas, and all other hydrocarbon substances produced and

sold from the field. To ensure that Indian lessors receive the maximum

revenues from mineral resources on their land consistent with the

Secretary's trust responsibility and lease terms, MMS is adopting a

minimum value for gas plant products in the final rule. We have

researched the problem with the availability of published price data

and determined that the necessary pricing data are available within a

week after the end of the month. We appreciate the comments received in

response to the specific issues and because no viable alternatives were

suggested we will not make any changes in the final rule.

Non-Binding Guidance Under Sec. 206.174(f)

The rule provides that lessees can request and MMS can provide non-

binding valuation guidance. MMS cannot issue binding guidance regarding

valuation. If a lessee seeks binding guidance, it must ask the

Assistant Secretary.

Comment on Sec. 206.174(l)(1). Seven commenters stated that audit

closure should not just be limited to leases in Montana and North

Dakota. The same commenters also recommend deleting the requirement to

report adjustments that would result in additional royalty.

Response. MMS has determined that lessees must make adjustments

sooner, and MMS must complete audits sooner for leases in Montana and

North Dakota. 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. The Committee discussed what would happen if

an area such as the San Juan Basin were disqualified as an index area,

and agreed that time limitations would not be appropriate in that case.

Naming Montana and North Dakota was the most straightforward way to

write the rule. Otherwise, we would need to discuss what happens if an

area such as the San Juan Basin becomes disqualified as an index area.

We did not make any changes in the final rule.

Comment on Sec. 206.174(l)(1)(ii). Two commenters suggested that to

conform to parallel language in paragraph (l)(1)(i), the closing

language of the last sentence should be amended to read, ``after the

last day of the 12th month following the last day to report

adjustments.''

Response. We agree and made the change in the final rule.

Comment on Sec. 206.174(l)(2)(i). Two commenters suggested amending

the opening phrase of this paragraph to read, ``If you have a pending

dispute with your purchaser that affects valuation. * * *'' These

commenters feel that MMS might otherwise unnecessarily try to avoid

audit closure.

Response. MMS agrees and we made the change in the final rule.

Comment on Sec. 206.174(l)(2)(i). Two commenters suggested amending

the opening phrase of this paragraph to read, ``If you have a pending

dispute that affects valuation with the person transporting. * * *''

Response. MMS agrees and we made the change in the final rule. We

also consolidated paragraphs (i) and (ii) in

[[Page 43511]]

the final rule and adjusted the numbering accordingly.

Comment on Sec. 206.174(l)(2)(ii). Two commenters suggested that

this provision should be modified to read, ``If there is a written

agreement between you and MMS or its delegee to extend the time limit,

the time period is extended * * *.''

Response. We made the proposed change in the final rule.

Comment on Sec. 206.176(a)(1)(i) and (ii). Five commenters

recommended replacing the word ``including * * * applicable

allowances'' with the word ``less'' to avoid the implication that

allowances are not deductible.

Response. We agree and made the suggested word change where

appropriate in the final rule.

Comment on Sec. 206.176(c). Eight commenters stated that the

Committee agreed that the gas must be traced to the mainline. Whether

the pipeline has an index is irrelevant and in any case does not take

into account valuation in nonindex areas. This reference should also be

corrected in Sec. 206.172(b)(1)(ii) and wherever discussed in the

preamble.

Response. We generally agree with the commenters and note that

although the Committee spent considerable time trying to determine the

correct wording, no decision was ever reached. We changed the wording

of the first sentence in Sec. 206.176(c) of the final rule by adding

the phrase ``* * * or into a mainline pipeline not in an index zone.''

We did not change the wording in Sec. 206.172(b)(1)(ii) for the reasons

discussed above. We did not define mainline but intend it to have the

same characteristics as a pipeline in an index zone with an index. We

have also added wording clarifying that accounting for comparison is

not required if the gas produced from the lease is not processed.

Comment on Sec. 206.176(e). Two commenters believe there is no need

to compute the weighted average Btu when the alternative method is not

being used. This paragraph need only state that you do not have to

perform dual accounting for a facility measurement point with a Btu

content of less than 1,000 Btu/cf. Likewise, the cross-reference to

Sec. 206.173 is not necessary.

Response. We believe that the cross-reference adds clarity, and we

did not make the change in the final rule.

Comment on Sec. 206.178(a)(1)(i). One commenter stated that

transportation contracts, invoices, or non-arm's-length transportation

cost documentation should be made available only upon audit and review.

One commenter supported the routine submittal of transportation

contracts because the information contained in those contracts will

permit the timely verification of the deduction and satisfies the

Committee's goal related to closure.

Response. MMS agrees with the need to routinely submit

transportation contracts, and we did not make any changes in the final

rule.

Comment on Sec. 206.178(f). Two commenters stated that the first

sentence of this paragraph should specify that ``you are required to

report and pay additional royalties on the difference, plus interest *

* *.''

Response. We do not believe that the additional wording is

necessary and did not make any changes in the final rule.

Comment on Sec. 206.178(g). Seven commenters recommended that the

exception for Federal Energy Regulatory Commission (FERC) or State-

approved tariffs contained in the regulations published in 1988 be

reinstated in the final rule.

Response. We will allow the lessee to deduct only those costs

associated with specifically identifiable actual or theoretical losses

that are part of the lessee's arm's-length transportation contract. We

did not make any change in the final rule.

Comment on Sec. 206.179. One commenter agreed that MMS should not

allow extraordinary cost deductions. Two commenters believe that the

provisions in the 1988 regulations covering extraordinary processing

allowances should be reinstated in the rule.

Response. MMS believes at this time that it is a better exercise of

the Secretary's trust responsibility to not allow extraordinary cost

allowances for Indian leases.

Comment on Sec. 206.179(f). Two commenters believe that this

paragraph is out of place. It should be moved to Sec. 220.550(d) and

should include unprocessed gas as well as residue gas and gas plant

products.

Response. We assume that the commenters made a typographic error

and the correct cite should be Sec. 202.550(d). We do not believe that

moving the paragraph will add to or clarify the rule. No change was

made in the final rule.

FERC Order 636 Changes. On December 16, 1997, MMS issued a final

regulation amending the existing transportation allowance regulation

for both Federal and Indian leases (62 FR 65753). These changes result

from FERC Order 636.

Many of the transportation allowance provisions changed in that

rulemaking were the same as those proposed in this rulemaking.

Therefore, this final rule incorporates changes to the transportation

allowance rules in Secs. 206.177 and 206.178 resulting from the recent

final rule.

Paperwork Reduction Act

MMS requested comments on two new forms, Form MMS-4410,

Certification for Not Performing Accounting for Comparison (Dual

Accounting), and Form MMS-4411, Safety Net Report, as they relate to

the Paperwork Reduction Act.

Comment on the Paperwork Reduction Act. Eleven commenters believe

that Form MMS-4410 is unnecessary because the same result can be more

efficiently accomplished through the use of a specific transaction code

on Form MMS-2014. These same commenters stated that because they are

totally opposed to the entire ``safety net'' concept, Form MMS-4411 is

not needed. The eleven commenters also believe that MMS's estimate of

additional costs to the entire industry of only $935,000 per year is

absurdly low.

Response. Form MMS-4410 will ensure that the lessee is not in

violation of lease terms specifying dual accounting by verifying

whether or not dual accounting is required. The form will benefit

industry because, by submitting the form, the lessee will not have to

perform dual accounting. Further, the form is only a one time

certification, which will require less burden than using a reporting

code on Form MMS-2014 that would have to be used for every report

month. Form MMS-4411 is critical in using the index pricing method to

satisfy the gross proceeds and major portion requirements of Indian

leases. The form is necessary to ensure that index pricing represents

market value and that the tribes do not suffer significant revenue

losses. The commenters' statement that the $935,000 estimate is too low

was not supported with any verifying data of what the estimate should

be. MMS performed an analysis to determine this estimate, as explained

in the September 23, 1996, proposed rule, and maintains that this

estimate is reasonable.

III. Principal Changes between the Proposed Rule and the Final Rule

Addition of Sec. 206.172(f) and (g). The final rule adds additional

paragraphs (f) and (g) to Sec. 206.172. Paragraph (f) permits an Indian

tribe to request that some or all of its leases be excluded from

valuation under Sec. 206.172. If MMS, after consultation with the

Bureau of Indian Affairs (BIA), approves the

[[Page 43512]]

request, value is determined under Sec. 206.174 beginning with

production on the first day of the second month following the date MMS

publishes notice in the Federal Register. If the tribe requests to

exclude only some of its leases, the request will only be approved if

the leases may be segregated into one or more groups based on fields

within the reservation.

This change is included in the final rule because a revenue

analysis indicated the Jicarilla Apache Tribe would receive less

revenue under the index methodology than under a gross proceeds

methodology. Specifically, royalties reported to MMS on MMS's Form MMS-

2014 for 1995 and 1996 exceeded the calculated values using the index

formula in Sec. 206.172. The proposed rule provided for MMS to

disqualify an index zone, but not to disqualify a reservation within an

index zone.

A tribe may also ask MMS to terminate this exclusion. If MMS, after

consultation with the BIA, terminates the exclusion, value would be

determined under Sec. 206.172. Termination of an exclusion cannot take

effect earlier than 1 year after the first day of the production month

that the exclusion was effective.

Paragraph (g) for Indian allotted leases contains provisions

similar to paragraph (f) and provides that MMS, with BIA consultation,

may exclude any allotted leases from valuation under Sec. 206.172.

Addition of Sec. 206.174(a)(4)(iv). A new paragraph (iv) in

Sec. 206.174(a)(4) permits using data other than values reported on

Form MMS-2014 in calculating the major portion value. The alternative

data would be data for production in the designated area reported to a

State tax authority or price data from leases MMS has reviewed in the

designated area. This change was needed because the revenue analysis

indicated that some Indian leases in Oklahoma would receive less

revenue under the index methodology than under a gross proceeds

methodology and we therefore expect that several tribes in Oklahoma

will request their leases to be excluded from index valuation. Indian

gas production is only about 2 percent of production in Oklahoma. Since

this amount of gas is too small to be representative of all gas

production values in a designated area, we needed an additional data

source beyond information on a Form MMS-2014. The revenue analysis for

the Jicarilla Apache reservation showed similar results and under

Sec. 206.172(f), and MMS expects the Jicarilla Apache will request its

leases to be excluded from index valuation.

IV. Procedural Matters

Your Comments Are Important

The Small Business and Agriculture Regulatory Enforcement Ombudsman

and 10 Regional Fairness Boards were established to receive comments

from small businesses about federal agency enforcement actions. The

Ombudsman will annually evaluate the enforcement activities and rate

each agency's responsiveness to small business. If you wish to comment

on the enforcement actions in this final rule, call 1-888-734-3247.

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.).

Approximately 700 entities pay royalties to MMS on production from

Indian lands, 400 of which are small businesses because they employ 500

or less employees. This rule will not have a significant administrative

impact on these small entities because it decreases rather than

increases the reporting burden. The reduced reporting results from

using the alternative method for dual accounting and the relief from

complying with major portion requirements under index pricing. For

example, the average Indian royalty payor will expend approximately

$8,500 less annually for administrative costs to comply with this

amended rule than under existing regulations. We estimate that the 200

smallest companies (0-4 employees) would have an average administrative

savings of $700 per year.

The rule would also have a royalty impact on small businesses due

to the index pricing formula for index-based areas and the major

portion provision for non-index areas. We estimate that 35 percent of

the total gas royalties paid on Indian tribal lands derive from the 400

small businesses that pay Indian gas royalties.

In our cost benefit analysis of the rule's impact, we estimated

that the index pricing formula would increase Indian revenues by about

$ 2.4 million annually. Therefore, small businesses would incur an

annual increase of about $2,100 per company ($2,400,000 x .35

400). This represents about a 5 percent increase in royalties, so a

very small company (e.g., 0-4 employees) that pays, for example, only

$500 per year in royalties would pay approximately an additional $25.

In non-index areas, we estimate that the major portion provisions

of the new rule would increase Indian revenues by $57,000 annually.

Small businesses on average would account for about $50 each ($57,000

x .35 400). However, given the significant administrative

savings of the rule described above, we believe any increase in

royalties paid by small companies will be more than offset by savings

in reporting burdens.

Likewise, this rule will not adversely impact small tribal

governments. This rule will increase annual royalty revenues to tribal

governments by approximately $2.5 million.

Unfunded Mandates Reform Act of 1995

This Department has determined and certifies according to the

Unfunded Mandates Reform Act, 2 U.S.C. 1531 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 this rule is not a governmental

action capable of interference with constitutionally protected property

rights. Thus, a Takings Implication Assessment need not be prepared

under Executive Order 12630, ``Governmental Actions and Interference

with Constitutionally Protected Property Rights.''

Executive Order 12988

The Department has certified to the Office of Management and Budget

that this rule meets the applicable 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. MMS estimates that this rule will result in an overall

$7.4 million administrative cost savings to industry.

Paperwork Reduction Act

This final rule contains information collection requirements. These

requirements have been approved by the Office of Management and Budget

(OMB) and assigned OMB Control Numbers 1010-0075.

As discussed below, this final rule impacts an existing collection

of information on Forms MMS-4109 and MMS-4295, which has 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

[[Page 43513]]

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 Publications Staff, PO Box 25165,

MS 3021, Denver, Colorado 80225-0165; courier address is: Building 85,

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

RMP.[email protected].

As a predecessor to this rulemaking, on September 23, 1996, MMS

published in the Federal Register a Notice of Proposed Rulemaking (NPR)

(61 FR 49894) to amend its regulations governing the valuation for

royalty purposes of natural gas produced from Indian leases. The NPR

introduced two new forms--Form MMS-4410, Certification for Not

Performing Accounting for Comparison (Dual Accounting) (OMB Control

Number 1010-0104), and Form MMS-4411, Safety Net Report (OMB Control

Number 1010-0103). These forms were approved by OMB on November 5,

1996. Forms MMS-4295 and 4109 were also mentioned in this NPR. No

comments were received from the public on these allowance forms.

OMB may make a decision to approve or disapprove this collection of

information after 30 days from receipt of our request. Therefore, your

comments are best assured of being considered by OMB if OMB receives

them within that time period. However, MMS will consider all comments

received to determine if a further rulemaking is necessary.

The burden hours associated with the existing information

collection titled Gas Processing Allowance Summary Report (Form MMS-

4109) and Gas Transportation Allowance Report (Form MMS-4295), OMB

Control Number 1010-0075, will be reduced by this final rulemaking.

Instead of submitting estimated processing or transportation cost

information on the forms and then following up with actual cost

information at the end of the reporting cycle, the rule will require

only responses with actual cost information. In addition, Indian

lessees that have arm's-length transportation and processing contracts

will submit copies of the actual contracts to MMS.

MMS estimates that 65 Indian lessees will submit approximately

3,000 allowance data lines annually. Lessees may be involved in more

than one type of allowance proposal and may submit both a processing

allowance line and a transportation allowance line. Based on past

experience, MMS estimates that lessees can complete an allowance data

line in about \1/4\ hour.

The estimate of the total annual burden hours to respondents for

this information collection is 750 hours (3,000 allowance data lines

x \1/4\ hour). The Gas Transportation Allowance Report, Form MMS-4295,

accounts for approximately 2,400 responses annually (80 percent of the

forms received), and the Gas Processing Allowance Summary Report, Form

MMS-4109, accounts for approximately 600 responses annually (20 percent

of the forms received). Therefore, the annual estimate of the burden

hours by form is 600 hours for Form MMS-4295 and 150 hours for Form

MMS-4109.

The MMS estimates that this information collection will result in a

decrease to industry of about 2,755 burden hours annually. The MMS

attributes this decrease primarily to the decrease in the number of

responses to only actual cost information as discussed above. A further

decrease will result from certain lessees electing the alternative

method for valuing processed gas, which requires no processing

allowance to be taken and no accompanying allowance report to be

submitted.

In compliance with the Paperwork Reduction Act of 1995, Section

3506 (c)(2)(A), we are notifying you, members of the public and

affected agencies, of this collection of information, and are inviting

your comments. For instance your comments may address the following

areas. Is this information collection necessary for us to properly do

our job? Have we accurately estimated the industry burden for

responding to this collection? Can we enhance the quality, utility, and

clarity of the information we collect? Can we lessen the burden of this

information collection on the respondents by using 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 determined that this rulemaking is not a major Federal action

significantly affecting the quality of the human environment, and a

detailed statement under section 102(2)(C) of the National

Environmental Policy Act of 1969 (42 U.S.C. 4332(2)(C)) is not

required.

List of Subjects

30 CFR Part 202

Coal, Continental shelf, Geothermal energy, Government contracts,

Indians--lands, Mineral royalties, Natural gas, Petroleum, Public

lands--mineral resources, Reporting and recordkeeping requirements.

30 CFR Part 206

Coal, Continental shelf, Geothermal energy, Government contracts,

Indians-lands, Mineral royalties, Natural gas, Petroleum, Public

lands--mineral resources, Reporting and recordkeeping requirements.

Dated: March 23, 1999.

Sylvia V. Baca,

Assistant Secretary--Land and Minerals Management.

For the reasons set out in the preamble, 30 CFR parts 202 and 206

are 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.

Sec. 202.51 [Amended]

2. Paragraph (b) of Sec. 202.51 is revised to read as follows:

* * * * *

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

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

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

read as follows:

Subpart D--Federal Gas

Sec. 202.150 [Amended]

4. In Sec. 202.150 the words ``or Indian'' are removed from.

(b)(1), (e)(1) and (e)(2).

Sec. 202.150 [Amended]

5. In Sec. 202.150 the words ``and Indian'' and ``or Indian'' are

removed from paragraph (f).

Sec. 202.151 [Amended]

6. In Sec. 202.151, the words ``and Indian'' are removed from

paragraph (a)(2).

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

[[Page 43514]]

Subpart J--Gas Production from Indian Leases

Sec.

202.550 How do I determine the royalty due on gas production?

202.551 How do I determine the volume of production for which I

must pay royalty if my lease is not in an approved Federal unit or

communitization agreement (AFA)?

202.552 How do I determine how much royalty I must pay if my lease

is in an approved Federal unit or communitization agreement (AFA)?

202.553 How do I value my production if I take more than my

entitled share?

202.554 How do I value my production that I do not take if I take

less than my entitled share?

202.555 What portion of the gas that I produce is subject to

royalty?

202.556 How do I determine the value of avoidably lost, wasted, or

drained gas?

202.557 Must I pay royalty on insurance compensation for

unavoidably lost gas?

202.558 What standards do I use to report and pay royalties on gas?

Subpart J-- Gas Production From Indian Leases

Sec. 202.550 How do I determine the royalty due on gas production?

If you produce gas from an Indian lease subject to this subpart,

you must determine and pay royalties on gas production as specified in

this section.

(a) Royalty rate. You must calculate your royalty using the royalty

rate in the lease.

(b) Payment in value or in kind. You must pay royalty in value

unless:

(1) The Tribal lessor requires payment in kind; or

(2) You have a lease on allotted lands and MMS requires payment in

kind.

(c) Royalty calculation. You must use the following calculations to

determine royalty due on the production from or attributable to your

lease.

(1) When paid in value, the royalty due is the unit value of

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

multiplied by the volume of production multiplied by the royalty rate

in the lease.

(2) When paid in kind, the royalty due is the volume of production

multiplied by the royalty rate.

(d) Reduced royalty rate. The Indian lessor and the Secretary may

approve a request for a royalty rate reduction. In your request you

must demonstrate economic hardship.

(e) Reporting and paying. You must report and pay royalties as

provided in part 218 of this title.

Sec. 202.551 How do I determine the volume of production for which I

must pay royalty if my lease is not in an approved Federal unit or

communitization agreement (AFA)?

(a) You are liable for royalty on your entitled share of gas

production from your Indian lease, except as provided in Secs. 202.555,

202.556, and 202.557.

(b) You and all other persons paying royalties on the lease must

report and pay royalties based on your takes. If another person takes

some of your entitled share but does not pay the royalties owed, you

are liable for those royalties.

(c) You and all other persons paying royalties on the lease may ask

MMS for permission to report and pay royalties based on your

entitlements. In that event, MMS will provide valuation instructions

consistent with this part and part 206 of this title.

Sec. 202.552 How do I determine how much royalty I must pay if my

lease is in an approved Federal unit or communitization agreement

(AFA)?

You must pay royalties each month on production allocated to your

lease under the terms of an AFA. To determine the volume and the value

of your production, you must follow these three steps:

(a) You must determine the volume of your entitled share of

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

include production from more than one AFA.

(b) You must value the production you take using 30 CFR part 206.

If you take more than your entitled share of production, see

Sec. 202.553 for information on how to value this production. If you

take less than your entitled share of production, see Sec. 202.554 for

information on how to value production you are entitled to but do not

take.

Sec. 202.553 How do I value my production if I take more than my

entitled share?

If you take more than your entitled share of production from a

lease in an AFA for any month, you must determine the weighted-average

value of all of the production that you take using the procedures in 30

CFR part 206, and use that value for your entitled share of production.

Sec. 202.554 How do I value my production that I do not take if I take

less than my entitled share?

If you take none or only part of your entitled production from a

lease in an AFA for any month, use this section to value the production

that you are entitled to but do not take.

(a) If you take a significant volume of production from your lease

during the month, you must determine the weighted average value of the

production that you take using 30 CFR part 206, and use that value for

the production that you do not take.

(b) If you do not take a significant volume of production from your

lease during the month, you must use paragraph (c) or (d) of this

section, whichever applies.

(c) In a month where you do not take production or take an

insignificant volume, and if you would have used Sec. 206.172(b) to

value the production if you had taken it, you must determine the value

of production not taken for that month under Sec. 206.172(b) as if you

had taken it.

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

lease in an AFA, and if that production cannot be valued under

Sec. 206.172(b), then you must determine the value of the production

that you do not take using the first of the following methods that

applies:

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

CFR part 206) in that month from other leases in the same AFA.

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

CFR part 206) in that month from other leases in the same field or

area.

(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.

(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.

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

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

(e) You may take less than your entitled share of AFA production

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

share under this section. If you do, 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. The provisions of this

paragraph (e) also apply when the other AFA participants pay you money

to balance your account.

Sec. 202.555 What portion of the gas that I produce is subject to

royalty?

(a) All gas produced from or allocated to your Indian lease is

subject to royalty except the following:

(1) Gas that is unavoidably lost.

[[Page 43515]]

(2) Gas that is used on, or for the benefit of, the lease.

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

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

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

(b) 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 for one of the following purposes:

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

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

(2) At a production facility handling unitized or communitized

production.

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

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

Sec. 202.556 How do I determine the value of avoidably lost, wasted,

or drained gas?

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 under 30 CFR part 206.

Sec. 202.557 Must I pay royalty on insurance compensation for

unavoidably lost gas?

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.

Sec. 202.558 What standards do I use to report and pay royalties on

gas?

(a) You must report gas volumes as follows:

(1) Report gas volumes and Btu heating values, if applicable, under

the same degree of water saturation. Report gas volumes and Btu heating

value at a standard pressure base of 14.73 psia and a standard

temperature of 60 degrees Fahrenheit. Report gas volumes in units of

1,000 cubic feet (Mcf).

(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) You must report residue gas and gas plant product volumes as

follows:

(1) 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) Report natural gas liquid (NGL) volumes in standard U.S.

gallons (231 cubic inches) at 60 degrees F.

(3) Report sulfur (S) volumes in long tons (2,240 pounds).

PART 206--PRODUCT VALUATION

8. The authority citation for 30 CFR 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 does this subpart contain?

206.171 What definitions apply to this subpart?

206.172 How do I value gas produced from leases in an index zone?

206.173 How do I calculate the alternative methodology for dual

accounting?

206.174 How do I value gas production when an index-based method

cannot be used?

206.175 How do I determine quantities and qualities of production

for computing royalties?

206.176 How do I perform accounting for comparison?

Transportation Allowances

206.177 What general requirements regarding transportation

allowances apply to me?

206.178 How do I determine a transportation allowance?

Processing Allowances

206.179 What general requirements regarding processing allowances

apply to me?

206.180 How do I determine an actual processing allowance?

206.181 How do I establish processing costs for dual accounting

purposes when I do not process the gas?

Subpart E--Indian Gas

Sec. 206.170 What does this subpart contain?

This subpart contains 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 on Indian allotted lands, 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 the governing mineral leasing laws,

treaties, and lease terms.

Sec. 206.171 What definitions apply to this subpart?

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 departmental regulations.

Area means a geographic region at least as large as the defined

limits of an oil or gas field, in which oil or gas lease products have

similar quality, economic, or legal characteristics. An area may be 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

[[Page 43516]]

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. The following percentages (based on the

instruments of ownership of the voting securities of an entity, or

based on other forms of ownership) determine if persons are affiliated:

(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 under 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. However, it does not include residue gas.

Gathering means the movement of lease production to a central

accumulation 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, 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 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)(2).

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.

[[Page 43517]]

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

(including operating rights owners) as well as an operator or payor who

has no interest in the lease but who has assumed the royalty payment

responsibility.

Like-quality lease products means lease products which have similar

chemical, physical, and legal characteristics.

Marketable condition means a condition in which lease products are

sufficiently free from impurities and otherwise so conditioned 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 of

1982, 30 U.S.C. 1701 et seq. or other applicable agreements.

Minimum royalty means that minimum amount of annual royalty that

the lessee must pay 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, or heavier liquid hydrocarbons.

Net-back method (or work-back method) means a method for

calculating market value of gas at the lease under which costs of

transportation, processing, and 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 (or 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.

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,

desulphurization (or ``sweetening''), 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 do I value gas produced from leases in an index zone?

(a) What leases this section applies to. 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.

(1) You must use the valuation provision of this section if your

lease is in an index zone and meets one of the following two

requirements:

(i) Has a major portion provision;

(ii) Does not have a major portion provision, but 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, you must

determine the value of these products under Sec. 206.174.

(b) Valuing residue gas and gas before processing. (1) Except as

provided in paragraphs (e), (f), and (g) of this section, this

paragraph (b) explains how you must value the following four types of

gas:

(i) Gas production before processing;

(ii) Gas production that you certify on Form MMS-4410,

Certification for Not Performing Accounting for Comparison (Dual

Accounting), is not processed before it flows into a pipeline with an

index but which may be processed later;

(iii) Residue gas after processing; and

(iv) Gas that is never processed.

(2) The value of gas production that is not sold under an arm's-

length dedicated contract is the index-based value determined under

paragraph (d) of this section unless the gas was subject to a previous

contract which was part of a gas contract settlement. If the previous

contract was subject to a gas contract settlement and if the royalty-

bearing contract settlement proceeds per MMBtu added to the 80 percent

of the safety net prices calculated at Sec. 206.172(e)(4)(i) exceeds

the index-based value that applies to the gas under this section

(including any adjustments required under Sec. 206.176), then the value

of the gas is the higher of the value determined under this section

(including any adjustments required under Sec. 206.176) or

Sec. 206.174.

(3) The value of gas production that is sold under an arm's-length

dedicated contract 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(b).

(c) Valuing gas that is processed before it flows into a pipeline

with an index. Except as provided in paragraphs (e), (f), and (g) 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 this gas production based on the higher of the following two

values:

(1) The value of the gas before processing determined under

paragraph (b) of this section.

[[Page 43518]]

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

alternative dual accounting value under Sec. 206.173 or the sum of the

following three values:

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

or (3) of this section, as applicable;

(ii) The value of the gas plant products determined under

Sec. 206.174, less any applicable processing and/or transportation

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) Determining 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 use the following procedures:

(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; and

(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 five 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's 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 the following five criteria:

(i) Publications buyers and sellers frequently use;

(ii) Publications frequently referenced in purchase or sales

contracts;

(iii) Publications that use adequate survey techniques, including

the gathering of information from a substantial number of sales;

(iv) Publications that 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.

(e) Determining the minimum value for royalty purposes of gas sold

beyond the first index pricing point. (1) Notwithstanding any other

provision of this section, the value for royalty purposes of gas

production from an Indian lease that is sold beyond the first index

pricing point through which it flows 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 (S) for an index zone is the volume-

weighted average contract price per delivered MMBtu under your or your

affiliate's arm's-length contracts for the disposition of residue gas

or unprocessed gas produced from your Indian leases in that index zone

as computed under this paragraph (e)(3).

(i) Include in your calculation only sales under those contracts

that establish a delivery point beyond the first index pricing point

through which the gas flows, and that include any gas produced from or

allocable to one or more of your Indian leases in that index zone, even

if the contract also includes gas produced from Federal, State, or fee

properties. Include in your volume-weighted average calculation those

volumes that are allocable to your Indian leases in that index zone.

(ii) Do not reduce the contract price for any transportation costs

incurred to deliver the gas to the purchaser.

(iii) For purposes of this paragraph (e), the contract price will

not include the following amounts:

(A) Any amounts you receive in compromise or settlement of a

predecessor contract for that gas;

(B) Deductions for you or any other person to put gas production

into marketable condition or to market the gas; and

(C) Any amounts related to marketable securities associated with

the sales contract.

(4) Next, you must determine for each month the safety net

differential (SND). You must perform this calculation separately for

each index zone.

(i) For each index zone, the safety net differential is equal to:

SND = [(0.80 x S) - (1.25 x I)] where (I) is the index-based value

determined under 30 CFR 206.172(d).

(ii) If the safety net differential is positive you owe additional

royalties.

(5)(i) To calculate the additional royalties you owe, make the

following calculation for each of your Indian leases in that index zone

that produced gas 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) of this section:

Lease royalties owed = SND x V x R, where R = the lease

royalty rate and V = the volume allocable to the lease which

produced gas that was sold beyond the first index pricing point.

(ii) If gas produced from any of your Indian leases is commingled

or pooled with gas produced from non-Indian properties, and if any of

the combined gas is sold at a delivery point beyond the first index

pricing point through which the gas flows, then the volume allocable to

each Indian lease for which gas was sold beyond the first index

[[Page 43519]]

pricing point in the calculation under paragraph (e)(5)(i) of this

section is the volume produced from the lease multiplied by the

proportion that the total volume of gas sold beyond the first index

pricing point bears to the total volume of gas commingled or pooled

from all properties.

(iii) Add the numbers calculated for each lease under paragraph

(e)(5)(i) of this section. The total is the additional royalty you owe.

(6) 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, Safety Net Report, 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; and

(iii) MMS may order you to amend your safety net price within one

year from the date your Form MMS-4411 is due or is filed, whichever is

later. If MMS does not order any amendments within that one-year

period, your safety net price calculation is final.

(f) Excluding some or all tribal leases from valuation under this

section. (1) An Indian tribe may ask MMS to exclude some or all of its

leases from valuation under this section. MMS will consult with BIA

regarding the request.

(i) If MMS approves the request for your lease, you must value your

production under Sec. 206.174 beginning with production on the first

day of the second month following the date MMS publishes notice of its

decision in the Federal Register.

(ii) If an Indian tribe requests exclusion from an index zone for

less than all of its leases, MMS will approve the request only if the

excluded leases may be segregated into one or more groups based on

separate fields within the reservation.

(2) An Indian tribe may ask MMS to terminate exclusion of its

leases from valuation under this section. MMS will consult with BIA

regarding the request.

(i) If MMS approves the request, you must value your production

under Sec. 206.172 beginning with production on the first day of the

second month following the date MMS publishes notice of its decision in

the Federal Register.

(ii) Termination of an exclusion under paragraph (f)(2)(i) of this

section cannot take effect earlier than 1 year after the first day of

the production month that the exclusion was effective.

(3) The Indian tribe's request to MMS under either paragraph (f)(1)

or (2) of this section must be in the form of a tribal resolution.

(g) Excluding Indian allotted leases from valuation under this

section. (1)(i) MMS may exclude any Indian allotted leases from

valuation under this section. MMS will consult with BIA regarding the

exclusion.

(ii) If MMS excludes your lease, you must value your production

under Sec. 206.174 beginning with production on the first day of the

second month following the date MMS publishes notice of its decision in

the Federal Register.

(iii) If MMS excludes any Indian allotted leases under this

paragraph (g)(1), it will exclude all Indian allotted leases in the

same field.

(2)(i) MMS may terminate the exclusion of any Indian allotted

leases from valuation under this section. MMS will consult with BIA

regarding the termination.

(ii) If MMS terminates the exclusion, you must value your

production under Sec. 206.172 beginning with production on the first

day of the second month following the date MMS publishes notice of its

decision in the Federal Register.

Sec. 206.173 How do I calculate the alternative methodology for dual

accounting?

(a) Electing a dual accounting method. (1) If you are required to

perform the accounting for comparison (dual accounting) under

Sec. 206.176, you have two choices. You may elect to perform the dual

accounting calculation according to either Sec. 206.176(a) (called

actual dual accounting), or paragraph (b) of this section (called the

alternative methodology for dual accounting).

(2) You must make a separate election to use the alternative

methodology for dual accounting 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.

(i) MMS will publish in the Federal Register a list of the lease

prefixes that will be associated with each designated area for purposes

of this section. The MMS-designated areas are as follows:

(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 for a

designated area, you must also use the alternative methodology for any

new wells commenced and any new leases acquired in the designated area

during the term of the election.

(b) Calculating value using the alternative methodology for dual

accounting. (1) The alternative methodology adjusts the value of gas

before processing determined under either Sec. 206.172 or Sec. 206.174

to provide the value of the gas after processing. You must use the

value of the gas after processing 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, as provided in the table in paragraph (b)(2)(ii) of this

section. If you have a direct or indirect ownership interest in the

plant where the gas is processed, the increase is higher, as provided

in paragraph (b)(2)(ii) of this section.

(2) To calculate the value of the gas after processing using the

alternative methodology for dual accounting, you must apply the

increase to the value before processing, determined in either

Sec. 206.172 or Sec. 206.174, as follows:

(i) Value of gas after processing = (value determined under either

Sec. 206.172 or Sec. 206.174, as applicable) x (1 + increment for

dual accounting); and

[[Page 43520]]

(ii) In this equation, the increment for dual accounting is the

number you take from the applicable Btu range, determined under

paragraph (b)(3) of this section, 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

1701+......................................... .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 any of your gas from the lease is processed during a month,

use the following two paragraphs to determine which amounts are subject

to dual accounting and which dual accounting method you must use.

(i) Weighted-average Btu content determined under paragraph (b)(3)

of this section is 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 if you

elected to use the alternative method under this section.

(ii) Weighted-average Btu content determined under paragraph (b)(3)

of this section is 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 are 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 do I value gas production when an index-based method

cannot be used?

(a) Situations in which an index-based method cannot be used. (1)

Gas production must be valued under this section in the following

situations.

(i) Your lease is not in an index zone (or MMS has excluded your

lease from an index zone).

(ii) If your lease is in an index zone and you sell your gas under

an arm's-length dedicated contract, then the value of your gas is the

higher of the value received under the dedicated contract determined

under Sec. 206.174(b) or the value under Sec. 206.172.

(iii) Also use this section to value any other gas production that

cannot be valued under Sec. 206.172, as well as gas plant products, and

to value components of the gas stream that have no Btu value (for

example, carbon dioxide, nitrogen, etc.).

(2) The value for royalty purposes of gas production 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.

(4) 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.

(i) The value of production you must initially report and pay is

the value determined in accordance with the other paragraphs of this

section.

(ii) MMS will determine the major portion value and notify you in

the Federal Register 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 by the due date specified in the 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.

(iii) Except as provided in paragraph (a)(4)(iv) of this section,

MMS will calculate the major portion value for each designated area

(which are the same designated areas as under Sec. 206.173) 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.

(iv) MMS may calculate the major portion value using different data

than the data described in paragraph (a)(4)(iii) of this section or

data to augment the data described in paragraph (a)(4)(iii) of this

section. This may include price data reported to the State tax

authority or price data from leases MMS has reviewed in the designated

area. MMS may use this alternate or the augmented data source beginning

with production on the first day of the month following the date MMS

publishes notice in the Federal Register that it is calculating the

major portion using a method in this paragraph (a)(4)(iv) of this

section.

(b) Arm's-length contracts. (1) 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 or your affiliate, except as provided in

paragraphs (b)(1)(ii)-(iv) of this section.

(i) 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 or your affiliate

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 or your affiliate, including

the additional consideration.

(iii) If MMS determines for gas valued under this paragraph that

the gross proceeds accruing to you or your affiliate 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 (3) of this section. In these

circumstances, MMS will notify you and give you an opportunity to

provide written information justifying your value.

(iv) This paragraph applies to situations where a pipeline

purchases

[[Page 43521]]

gas from a lessee according to a cash-out program under a

transportation contract. For all over-delivered volumes, the royalty

value is the price the pipeline is required to pay for volumes within

the tolerances for over-delivery specified in the transportation

contract. Use the same value for volumes that exceed the over-delivery

tolerances even if those volumes are subject to a lower price specified

in the transportation contract. However, if MMS determines that the

price specified in the transportation contract for over-delivered

volumes is unreasonably low, the lessees must value all over-delivered

volumes under paragraph (c)(2) or (3) of this section.

(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) Non-arm's-length contracts. 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 of the

following three methods:

(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.

(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 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.

(3) A net-back method or any other reasonable method to determine

value.

(d) Supporting data. 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.

(1) Such data will be subject to review and audit, and MMS will

direct you to use a different value if we determine upon review or

audit that the value you reported is inconsistent with the requirements

of these regulations.

(2) You must make all such data available upon request to the

authorized MMS or Indian representatives, to the Office of the

Inspector General of the Department, or other authorized persons. This

includes 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) Improper values. 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 on how to take that

credit.

(f) Value guidance. You may ask MMS for guidance in determining

value. You may propose a valuation method to MMS. Submit all available

data related to your proposal and any additional information MMS deems

necessary. MMS will promptly review your proposal and provide you with

a non-binding determination of the guidance you request.

(g) Minimum value of production. (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 (including its affiliates) 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 as

follows:

(i) Leases in certain States and areas have specific minimum

values.

(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,

Texas, 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, Kansas, 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;

and (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) Marketable condition/Marketing. You are required to place gas,

residue gas, and gas plant products in marketable condition and market

the gas for the mutual benefit of the lessee and the lessor at no cost

to the Indian lessor. 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 to place the gas, residue gas, or

gas plant products in marketable condition or to market the gas, the

cost of which ordinarily is your responsibility.

(i) Highest obtainable price or benefit. 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

[[Page 43522]]

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) Non-binding MMS reviews. 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 against the

Federal Government or its beneficiaries until the audit period is

formally closed.

(k) Confidential information. 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 limits 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 following the last day to report

adjustments.

(2) Exceptions to the time limits in paragraph (l)(1) of this

section are as follows:

(i) If you have a pending dispute with your purchaser or with the

person transporting or processing your gas production that affects

valuation, the time periods to make adjustments in paragraphs (l)(1)(i)

and (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 there is a written agreement between you and MMS or its

delegee (if applicable) to extend the time limit, the time period is

extended for the period stated in the agreement;

(iii) If there is a pending regulatory proceeding by any agency

with jurisdiction over sales prices for gas that could affect the value

of the gas, the time period to make adjustments in paragraphs (l)(1)(i)

and (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;

(iv) 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; and

(v) The time period in paragraphs (l)(1)(i) and (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 may easily

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 do I 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 if 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

[[Page 43523]]

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 of

gas plant products attributable to the lease 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 volumes of residue gas and

of gas plant products delivered from all leases by summing the

theoretical volumes of residue gas and of gas plant products delivered

from each lease; and

(iii) Third, calculate the theoretical quantities of net plant

output of residue gas and of gas plant products attributable to each

lease by multiplying the net plant output of residue gas, or gas plant

products, by the ratio in which the theoretical volumes of residue gas,

or gas plant products, is the numerator and the theoretical volume of

residue gas, or gas plant products, delivered from all leases is the

denominator.

(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 do I perform accounting for comparison?

(a) This section applies if the gas produced from your Indian lease

is processed 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 the following two

values:

(1) The combined value of the following products:

(i) The residue gas and gas plant products resulting from

processing the gas determined under either Sec. 206.172 or

Sec. 206.174, less 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. 206.52, less applicable

allowances.

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

either Sec. 206.172 or Sec. 206.174, 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 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 or into a mainline pipeline not

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 or the alternative dual

accounting methodology of Sec. 206.173, 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.

Transportation Allowances

Sec. 206.177 What general requirements regarding transportation

allowances apply to me?

(a) When you value gas under Sec. 206.174 at a point off the lease,

unit, or communitized area (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, unit, or

communitized area. 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, unit, or

communitized area. This would include, if appropriate, transportation

from the lease to a gas processing plant off the lease, unit, or

communitized area 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.

(c)(1) Except as provided in paragraphs (c)(2) and (3) of this

section, your transportation allowance deduction for each selling

arrangement may 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, MMS 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. Under no

circumstances may an allowance reduce the value for royalty purposes

under any selling arrangement to zero.

(3) Your 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.

(d) If MMS conducts a review 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 do I determine a transportation allowance?

(a) Determining a transportation allowance under an arm's-length

contract. (1) This paragraph explains how to determine your allowance

if you have an arm's-length transportation contract.

(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

(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 (e) 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

[[Page 43524]]

examine whether or not the contract reflects more than the

consideration actually transferred either directly or indirectly from

you to the transporter of 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) This paragraph explains how to allocate the costs to each

product 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.

(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 that the volume of

each product (excluding waste products which have no value) bears 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 that 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 we determine that

it meets one of the two following requirements:

(A) The methodology in paragraph (a)(2)(i) of this section cannot

be applied; and

(B) Your proposal is more reasonable than the methodology in

paragraph (a)(2)(i) of this section.

(3) This paragraph explains how to allocate costs to each product

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.

(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 price, 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 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) Determining a transportation allowance under a non-arm's-length

or no contract. (1) This paragraph explains how to determine your

allowance if you have a non-arm's-length transportation contract or no

contract.

(i) When you have a non-arm's-length transportation contract or no

contract, including those situations where you perform transportation

services for yourself, 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, Gas Transportation

Allowance Report, 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) This paragraph explains what actual transportation costs are

allowable under a non-arm's-length contract or no contract situation.

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) 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) that 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 that 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 that 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 that 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

[[Page 43525]]

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 that is determined under paragraph (b)(4) of

this section.

(3) This paragraph explains how to allocate transportation costs to

each product and transportation system.

(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 in the same proportion that the volume of each

product (excluding waste products that have no value) bears to the

volume of all products in the gaseous phase (excluding waste products

that have no value). Except as provided in this paragraph, you may not

take an allowance for transporting a product that 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 it meets one of the two following requirements:

(A) The methodology in paragraph (b)(3)(i) of this section cannot

be applied; and

(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) Using the alternative transportation calculation when you have

a non-arm's-length or no contract. (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. Your first election will remain in effect until the end of the

succeeding calendar year, except for elections effective January 1 that

will be effective only for that calendar year.

(d) Reporting your transportation allowance. (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 line

item on Form MMS-2014. MMS may approve a different reporting procedure

on allottee leases, and with lessor approval on tribal leases.

(e) Adjusting incorrect allowances. If for any month the

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

from the first day of the first month you deducted the improper

transportation allowance until the date you pay the royalties due. If

the 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.

(f) Determining allowable costs for transportation allowances.

Lessees may include, but are not limited to, the following costs in

determining the arm's-length transportation allowance under paragraph

(a) of this section or the non-arm's-length transportation allowance

under paragraph (b) of this section:

(1) Firm demand charges paid to pipelines. You must limit the

allowable costs for the firm demand charges to the applicable rate per

MMBtu multiplied by the actual volumes transported. You may not include

any losses incurred for previously purchased but unused firm capacity.

You also may not include any gains associated with releasing firm

capacity. If you receive a payment or credit from the pipeline for

penalty refunds, rate case refunds, or other reasons, you must reduce

the firm demand charge claimed on the Form MMS-2014. You must modify

the Form MMS-2014 by the amount received or credited for the affected

reporting period.

(2) Gas supply realignment (GSR) costs. The GSR costs result from a

pipeline reforming or terminating supply contracts with producers to

implement the restructuring requirements of FERC orders in 18 CFR part

284.

(3) Commodity charges. The commodity charge allows the pipeline to

recover the costs of providing service.

(4) Wheeling costs. Hub operators charge a wheeling cost for

transporting gas from one pipeline to either the same or another

pipeline through a market center or hub. A hub is a connected manifold

of pipelines through which a series of incoming pipelines are

interconnected to a series of outgoing pipelines.

(5) Gas Research Institute (GRI) fees. The GRI conducts research,

development, and commercialization programs on natural gas related

topics for the benefit of the U.S. gas industry and gas customers. GRI

fees are allowable provided such fees are mandatory in FERC-approved

tariffs.

(6) Annual Charge Adjustment (ACA) fees. FERC charges these fees to

pipelines to pay for its operating expenses.

(7) Payments (either volumetric or in value) for actual or

theoretical losses. This paragraph does not apply to non-

[[Page 43526]]

arm's-length transportation arrangements.

(8) Temporary storage services. This includes short duration

storage services offered by market centers or hubs (commonly referred

to as ``parking'' or ``banking''), or other temporary storage services

provided by pipeline transporters, whether actual or provided as a

matter of accounting. Temporary storage is limited to 30 days or less.

(9) Supplemental costs for compression, dehydration, and treatment

of gas. MMS allows these costs only if such services are required for

transportation and exceed the services necessary to place production

into marketable condition required under Sec. 206.174(h).

(g) Determining nonallowable costs for transportation allowances.

Lessees may not include the following costs in determining the arm's-

length transportation allowance under paragraph (a) of this section or

the non-arm's-length transportation allowance under paragraph (b) of

this section:

(1) Fees or costs incurred for storage. This includes storing

production in a storage facility, whether on or off the lease, for more

than 30 days.

(2) Aggregater/marketer fees. This includes fees you pay to another

person (including your affiliates) to market your gas, including

purchasing and reselling the gas, or finding or maintaining a market

for the gas production.

(3) Penalties you incur as shipper. These penalties include, but

are not limited to the following:

(i) Over-delivery cash-out penalties. This includes the difference

between the price the pipeline pays you for over-delivered volumes

outside the tolerances and the price you receive for over-delivered

volumes within tolerances.

(ii) Scheduling penalties. This includes penalties you incur for

differences between daily volumes delivered into the pipeline and

volumes scheduled or nominated at a receipt or delivery point.

(iii) Imbalance penalties. This includes penalties you incur

(generally on a monthly basis) for differences between volumes

delivered into the pipeline and volumes scheduled or nominated at a

receipt or delivery point.

(iv) Operational penalties. This includes fees you incur for

violation of the pipeline's curtailment or operational orders issued to

protect the operational integrity of the pipeline.

(4) Intra-hub transfer fees. These are fees you pay to hub

operators for administrative services (e.g., title transfer tracking)

necessary to account for the sale of gas within a hub.

(5) Other nonallowable costs. Any cost you incur for services you

are required to provide at no cost to the lessor.

(h) Other transportation cost determinations. You must follow the

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.

Processing Allowances

Sec. 206.179 What general requirements regarding processing allowances

apply to me?

(a) When you value any gas plant product under Sec. 206.174, 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. 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.

(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 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 that 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, that is reinjected into a reservoir

within the same lease, unit, or approved Federal agreement, until such

time as those products are finally produced from the reservoir for sale

or other disposition. 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 do I determine an actual processing allowance?

(a) Determining a processing allowance if you have an arms's-length

processing contract. (1) This paragraph explains how you determine an

allowance under an arm's-length processing contract.

(i) The processing allowance is the reasonable actual costs you

incur to process the gas under that contract. Paragraphs (a)(1)(ii) and

(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 that deducts the allowance on the Form

MMS-2014.

(ii) When MMS conducts reviews and audits, we 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

[[Page 43527]]

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 may not take an allowance for the costs of processing lease

production that 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 may not take a processing allowance for the costs

of processing lease production that is not royalty-bearing.

(4) If your payments for processing under an arm's-length contract

are not based on a dollar per unit price, you must convert whatever

consideration is paid to a dollar value equivalent for the purposes of

this section.

(b) Determining a processing allowance if you have a non-arm's-

length contract or no contract. (1) This paragraph applies if you have

a non-arm's-length processing contract or no contract, including those

situations where you perform processing for yourself.

(i) If you have a non-arm's-length contract or no contract, the

processing allowance is based upon your reasonable actual costs of

processing as provided in paragraph (b)(2) 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, Gas Processing Allowance Summary

Report, 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 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 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) that 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 that 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 that 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 that 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. A processing plant may be depreciated only once, regardless

of whether there is a change in ownership. Equipment may not be

depreciated below a reasonable salvage value. To compute a return on

undepreciated capital investment, you must 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 must

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 may not take an

allowance for the costs of processing lease production that is not

royalty-bearing.

(c) Reporting your processing allowance. (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 line

item on the Form MMS-2014. MMS may approve a different reporting

procedure for allottee leases, and with lessor approval on tribal

leases.

(d) Adjusting incorrect processing allowances. If for any month the

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 from the first

day of the first month you deducted a processing allowance until the

date you pay the royalties due. If the

[[Page 43528]]

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.

(e) 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 How

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