[Federal Register Volume 64, Number 153 (Tuesday, August 10, 1999)]
[Rules and Regulations]
[Pages 43506-43528]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 99-20376]
[[Page 43505]]
_______________________________________________________________________
Part IV
Department of the Interior
_______________________________________________________________________
Minerals Management Service
_______________________________________________________________________
30 CFR Parts 202 and 206
Amendments to Gas Valuation Regulations for Indian Leases; Final Rule
Federal Register / Vol. 64, No. 153 / Tuesday, August 10, 1999 /
Rules and Regulations
[[Page 43506]]
DEPARTMENT OF THE INTERIOR
Minerals Management Service
30 CFR Parts 202 and 206
RIN 1010-AB57
Amendments to Gas Valuation Regulations for Indian Leases
AGENCY: Minerals Management Service, Interior.
ACTION: Final rule.
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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.comments@mms.gov.
FOR FURTHER INFORMATION CONTACT: David S. Guzy, Chief, Rules and
Publications Staff; phone (303) 231-3432; fax (303) 231-3385; e-mail
david.guzy@mms.gov.
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.comments@mms.gov.
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 do I establish processing costs for dual accounting
purposes when I do not process the gas?
Where accounting for comparison (dual accounting) is required for
gas production from a lease but neither you nor someone acting on your
behalf processes the gas, and you have elected to perform actual dual
accounting under Sec. 206.176, you must use the first applicable of the
following methods to establish processing costs for dual accounting
purposes:
(a) The average of the costs established in your current arm's-
length processing agreements for gas from the lease, provided that some
gas has previously been processed under these agreements.
(b) The average of the costs established in your current arm's-
length processing agreements for gas from the lease, provided that the
agreements are in effect for plants to which the lease is physically
connected and under which gas from other leases in the field or area is
being or has been processed.
(c) A proposed comparable processing fee submitted to either the
tribe and MMS (for tribal leases) or MMS (for allotted leases) with
your supporting documentation submitted to MMS. If MMS does not take
action on your proposal within 120 days, the proposal will be deemed to
be denied and subject to appeal to the MMS Director under 30 CFR part
290.
(d) Processing costs based on the regulations in Secs. 206.179 and
206.180.
[FR Doc. 99-20376 Filed 8-9-99; 8:45 am]
BILLING CODE 4310-MR-P
