[Federal Register Volume 65, Number 3 (Wednesday, January 5, 2000)]
[Proposed Rules]
[Pages 403-419]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 00-58]
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DEPARTMENT OF THE INTERIOR
Minerals Management Service
30 CFR Part 206
RIN 1010-AC24
Establishing Oil Value for Royalty Due on Indian Leases
AGENCY: Minerals Management Service, Interior.
ACTION: Supplementary proposed rule.
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SUMMARY: The Minerals Management Service (MMS) is proposing further
changes to its proposed rulemaking regarding the valuation, for royalty
purposes, of crude oil produced from Indian leases. The MMS is
proposing to: Change which index prices would be used for valuation,
change how those index prices would apply, change how transportation
allowances would apply, and streamline proposed Form MMS-4416 for
computing adjustments to value for royalty purposes. These amendments
are intended to simplify and improve the proposed rule.
DATES: Your comments must be submitted on or before March 6, 2000.
ADDRESSES: Address your comments, suggestions, or objections regarding
this supplementary proposed rule to:
By regular U.S. mail. Minerals Management Service, Royalty
Management Program, Rules and Publications Staff, P.O. Box 25165, MS
3021, Denver, Colorado 80225-0165; or
By overnight mail or courier. Minerals Management Service, Royalty
Management Program, Building 85, Room A613, Denver Federal Center,
Denver, Colorado 80225; or
By e-mail. RMP.comments@mms.gov. Please submit Internet comments as
an ASCII file and avoid the use of special characters and any form of
encryption. Also, please include ``Attn: RIN 1010-AC24'' and your name
and return address in your Internet message. If you do not receive a
confirmation that we have received your Internet message, call the
contact person listed below.
Mail or hand-carry comments with respect to the information
collection
[[Page 404]]
burden of the proposed rule to the Office of Information and Regulatory
Affairs; Office of Management and Budget; Attention: Desk Officer for
the Department of the Interior (OMB control number 1010-NEW); 725 17th
Street, NW, Washington, DC 20503.
FOR FURTHER INFORMATION CONTACT: David S. Guzy, Chief, Rules and
Publications Staff, Royalty Management Program, Minerals Management
Service, telephone (303) 231-3432, fax (303) 231-3385, or e-mail
RMP.comments@mms.gov.
SUPPLEMENTARY INFORMATION:
I. Background
On February 12, 1998, MMS published a notice of proposed rulemaking
applicable exclusively to the valuation of crude oil produced from
Indian leases (63 FR 7089). The comment period for this proposed rule
was to close on April 13, 1998, but was extended to May 13, 1998 (63 FR
17249). MMS held two public workshops (63 FR 11384) on this proposed
rule: one in Albuquerque, New Mexico, on March 26, 1998; and one in
Lakewood, Colorado, on April 1, 1998. Comments received to date are
available for public inspection at the RMP offices in Lakewood, or on
the Internet at http://www.rmp.mms.gov. MMS will also place any
additional comments received on this rule on the Internet. Call David
Guzy at (303) 231-3432 for further information.
Because of the substantial comments received on the initial
proposal, comments made at the public workshops, and other feedback
from the Indian community, MMS is reopening certain provisions of the
rulemaking to public comment.
II. Revisions to Proposed Rule
After hearing public comments, MMS is proposing some changes to the
February 12, 1998, proposed rule. We summarize the proposed changes
below, as well as the related comments that prompted the changes. MMS
is requesting public comments on these proposed provisions.
Use of Spot Prices vs. New York Mercantile Exchange (NYMEX) Futures
Prices
In response to the February 12, 1998, proposed rule, several
commenters objected to the inclusion of NYMEX prices as one of the
three values compared to determine royalty value on Indian leases. They
argued that NYMEX prices are not attainable by everyone, that use of
NYMEX prices effectively moves valuation away from the lease, and that
using these prices would add administrative complexity. One comment
from an Indian tribe, however, said that use of NYMEX prices was long
overdue.
MMS now is proposing to use spot, rather than NYMEX, prices for
several reasons. First, we believe that when the NYMEX futures price,
properly adjusted for location and quality differences, is compared to
spot prices, it nearly duplicates those spot prices. Second,
application of spot prices would remove one portion of the necessary
adjustments to the NYMEX price--the leg between Cushing, Oklahoma, and
the market center location.
This supplementary proposed rule states, at proposed
Sec. 206.52(a), that one of the three comparative values used to
determine royalty value is the spot price:
(1) For the market center nearest your lease where spot prices are
published in an MMS-approved publication;
(2) For the crude oil most similar in quality to your oil; and
(3) For deliveries during the production month.
One exception is that for leases in the Rocky Mountain Region, the
appropriate market center and spot price would be at Cushing, Oklahoma
(redesignated paragraph (a)(1); previous paragraph (a)(1) was deleted
because it related to prompt months under NYMEX pricing). This is
because the otherwise-nearest spot price location is at Guernsey,
Wyoming, where we believe actual trading is too limited to result in a
reliable spot price.
To complement the change from NYMEX to spot prices, Sec. 206.51 of
this supplementary proposed rule is amended by revising the definitions
of ``Index pricing'' and ``MMS-approved publication'' and adding a
definition for ``Rocky Mountain Region'' as follows:
``Index pricing'' would mean using spot prices for royalty
valuation.
``MMS-approved publication'' would mean a publication MMS approves
for determining spot prices.
``Rocky Mountain Region'' would mean the States of Colorado,
Montana, North Dakota, South Dakota, Utah, and Wyoming.
We have also added, at proposed paragraph 206.52(a)(6), that MMS
periodically would publish in the Federal Register a list of approved
spot price publications based on certain criteria, including but not
limited to:
(i) Publications that buyers and sellers frequently use;
(ii) Publications frequently mentioned in purchase or sales
contracts;
(iii) Publications that use adequate survey techniques, including
development of spot price estimates based on daily surveys of buyers
and sellers of crude oil; and
(iv) Publications independent from MMS, other lessors, and lessees.
Proposed new paragraph (a)(7) states that any publication may
petition MMS to be added to the list of acceptable publications.
Proposed new paragraph (a)(8) states that MMS will specify the tables
you must use in the publications to determine the associated spot
prices.
Use of Average of High Daily Spot Prices Rather Than Average of Five
Highest NYMEX Settle Prices in a Given Month
We received a number of comments that applying the average of the
five highest NYMEX settle prices was unfair and unrealistic and that
this represented a price most sellers could not obtain under any
circumstances. We agree with this comment and, in addition to changing
from NYMEX to spot prices, have modified the subset of spot prices to
be used. Rather than applying the five highest spot prices in any given
month, we propose at Sec. 206.52(a) to use the average of the daily
high spot prices for that month in the selected publication. This
should better reflect values generally obtainable, while at the same
time fulfilling MMS's trust responsibility to Indian lessors.
Modifications to Major Portion Notification by MMS
Previously-proposed paragraph 206.52(c)(1) would have required MMS
to calculate major portion values within 120 days of each production
month. Although this should be possible in most cases, MMS can foresee
occasional problems in acquiring the needed data and performing the
major portion calculations within 120 days. Consequently, MMS proposes
to change paragraph 206.52(c)(1) by dropping the 120-day provision and
stating that MMS would notify lessees by publishing the major portion
value in the Federal Register. This should have no adverse impact on
royalty payors, because late payment interest would not begin to accrue
on any underpayment based on any additional amount owed as a result of
the higher major portion value until the due date of the amended Form
MMS-2014. Thus, no late payment interest would accrue on the higher
major portion value if the payor submitted an amended Form MMS-2014
within 30 days after MMS published the major portion value in the
Federal Register.
MMS also proposes to make changes in paragraphs 206.52(c)(4) and
206.52(d) to reflect that MMS would notify lessees of the major portion
value by publication in the Federal Register.
[[Page 405]]
Transportation Costs From Lease Versus Reservation Boundary
We received a number of comments that MMS should not limit
transportation deductions to those incurred beyond the reservation
boundary. The commenters said that there is no requirement that lessees
transport oil within a designated area at no cost to the lessor, and
that transportation costs should be calculated from the point where oil
is measured for sale. We agree with these comments and propose to
change previously-proposed Secs. 206.60 and 206.61 to reflect the
permissibility of transportation deductions from the lease or unit
rather than the designated area, as well as the reality of exchange
agreements whose first transfer point is at the lease or unit or an
associated aggregation point.
To complement the change to permitting transportation allowances
from the lease or unit rather than the designated area, and to better
represent exchange agreements whose initial transfer point is at an
aggregation point away from the lease or unit, Sec. 206.51 of this
supplementary proposed rule is amended by adding a definition of
``Aggregation point'' as follows:
``Aggregation point'' would mean a central point where production
is aggregated for shipment to market centers or refineries. It would
include, but not be limited to, blending and storage facilities and
connections where pipelines join. Pipeline terminations at refining
centers also would be classified as aggregation points. MMS
periodically would publish in the Federal Register a list of
aggregation points and associated market centers.
Proposed changes at Sec. 206.60 include:
(1) Modifying the table at paragraph (a)(1) to reflect
permissibility of transportation from the lease or unit, rather than
the designated area, to the point of sale;
(2) Eliminating existing paragraph (a)(2)(ii) to delete the
provision that transportation deductions are not permitted when the
sale or transfer takes place in the designated area;
(3) Redesignating existing paragraph (a)(2)(iii) as paragraph
(a)(2)(ii);
(4) Modifying the table at paragraph (b)(1) to reflect that the
transportation allowance may not exceed 50 percent of the calculated
spot, rather than NYMEX, price; and
(5) Amending paragraph (d) to reflect permissibility of location
and quality adjustments between the lease or unit and index pricing
point.
Proposed changes at Sec. 206.61 include:
(1) Modifying paragraph (c)(1) to reflect permissibility of
location and quality adjustments between the lease or unit and market
center;
(2) Eliminating existing paragraph (c)(1)(i) to acknowledge the
elimination of location differentials based on the difference in crude
oil values at the index pricing point and the appropriate market
center, due to the proposed change to begin with spot, rather than
NYMEX, prices;
(3) Rewording existing paragraph (c)(1)(ii) to reflect location
differentials between aggregation points and market centers, rather
than designated areas and market centers, and redesignating it as
paragraph (c)(1)(i);
(4) Rewording existing paragraph (c)(1)(iii) to similarly reflect
location differentials between aggregation points and market centers,
and redesignating it as paragraph (c)(1)(ii);
(5) Inserting new paragraph (c)(1)(iii) to reflect permissibility
of transportation deductions between the aggregation point and the
lease or unit;
(6) Rewording existing paragraph (c)(1)(iv) to reflect
permissibility of transportation deductions between the market center
and the lease or unit;
(7) Inserting new paragraph (c)(1)(v) to reflect potential quality
adjustments at the market center or other intermediate points;
(8) Modifying the table at paragraph (c)(2) to reflect changes
related to the permissibility of transportation deductions within the
designated area;
(9) Deleting paragraph (c)(2)(i) because it becomes unnecessary
given the proposed change to permit transportation deductions within
the designated area and the proposed changes regarding spot prices and
market centers at Sec. 206.52(a);
(10) Deleting paragraph (c)(2)(ii) because this language is now in
the table at paragraph (c)(2);
(11) Rewording paragraphs (c)(3) and (c)(3)(iii) to refer to
paragraph (c)(1)(ii) instead of (c)(1)(iii);
(12) Deleting paragraphs (c)(4), (c)(5), and (c)(6) relating to
publications used to calculate differentials in the previously-existing
but now-deleted paragraph (c)(1)(i); and
(13) Redesignating existing paragraph (c)(7) as paragraph (c)(4).
Modifications to Proposed Form MMS-4416
We received a number of comments that the data requirements for
completing Form MMS-4416 are too burdensome and the resultant MMS
calculations of location differentials would not be reliable. While we
do not agree with the latter comment, we agree that Form MMS-4416 can
be streamlined by eliminating or simplifying certain data requirements
and clarifying the instructions included with the form. In addition to
revising and clarifying the instructions, we propose to change
Sec. 206.61(d)(5) by stating that you must submit information on Form
MMS-4416 related to all of your crude oil production from Indian leases
in designated areas, rather than all production from designated areas.
This change should help to limit the administrative burden of the
information collection while still permitting MMS to acquire the
information needed to calculate relevant location differentials and
verify royalty values and differentials reported on Form MMS-2014. We
have attached a copy of the revised Form MMS-4416 and the associated
instructions for comment.
MMS specifically requests comments on the revised paragraphs
addressed in this notice. If you have commented already on other
portions of the rule, you do not need to resubmit those comments. MMS
will respond to all comments in the final rule.
III. Procedural Matters
1. Public Comment Policy
Our practice is to make comments, including names and home
addresses of respondents, available for public review during regular
business hours and on our Internet site at www.rmp.mms.gov. Individual
respondents may request that we withhold their home address from the
rulemaking record, which we will honor to the extent allowable by law.
There also may be circumstances in which we would withhold from the
rulemaking record a respondent's identity, as allowable by law. If you
wish us to withhold your name and/or address, you must state this
prominently at the beginning of your comments. However, we will not
consider anonymous comments. We will make all submissions from
organizations or businesses, and from individuals identifying
themselves as representatives or officials of organizations or
businesses, available for public inspection in their entirety.
2. Summary Cost and Benefit Data
We have summarized below the estimated costs and benefits of this
supplementary proposed rule to all potentially affected groups:
industry, State and local governments, Indian tribes and allottees (by
fund code), and the Federal Government. The costs are segregated into
two categories--those costs that would be incurred in the first year
after this rule is effective and those
[[Page 406]]
costs that would be incurred on a continuing basis each year
thereafter. The cost and benefit information in this Item 2 of
Procedural Matters is used as the basis for the Departmental
certifications in Items 3 through 11 below.
a. Industry
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/benefit amount
Description (see corresponding --------------------------------------
narrative below) First year Subsequent years
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(1) Cost--Net Negative Revenues.. $<4,667,510> <4,667,510>
(2) Cost--Equipment/Compliance... <1,687,500> <1,125,000>
(3) Cost--Completing Form MMS- <118,125> <118,125>
4416............................
(4) Cost--Filing new 2014 with <50,000> <50,000>
Major Portion Uplift............
(5) Benefit--Administrative 1,100,000 1,100,000
Savings.........................
--------------------------------------
Net Costs to Industry...... $<5,423,135> $<4,860,635>
------------------------------------------------------------------------
(1) Cost--Net Negative Revenues. We estimate that the oil valuation
changes proposed in this rule would increase the annual royalties
industry must pay to Indian tribes and allottees by $4,667,510. While
many variables (price of oil, change in lease operations, possible
royalty in kind sales, etc.) could influence the estimate up or down in
subsequent years, we did not make any assumptions regarding these
variables. Based on reported revenues by company in 1997, we calculate
that small businesses (by U.S. Small Business Administration criteria)
would pay approximately $1.4 million or roughly 30 percent of the
increase. Based on a study for 1997, there were 225 companies that paid
royalties for oil produced from Indian leases. Of that number, 173 were
small businesses. The computation of the additional mineral revenues
payable to Indian tribes and allottees can be found in section c below.
(2) Cost--Equipment/Compliance. Industry would also incur computer,
software acquisition, and other costs in order to conform with the new
reporting requirements. We estimate that to comply with the rule,
industry would need:
--A subscription to an industry newsletter (Platt's Oilgram or similar
publication).
--A computer with enough power to effectively run a spreadsheet.
--Spreadsheet software.
--Office space and filing equipment dedicated to maintenance of records
relating to the rule.
Although many companies already have these resources available and
would incur little additional expense, we estimate the following
additional costs:
Newsletter subscription: $2,000 per year
Computer acquisition: 2,000 one-time
Spreadsheet software: 500 one-time
Office space and file equipment ($250 per month for one year: 3,000 per
year
Total: $7,500
Because some of the costs are not incurred every year, we reduced
the costs for subsequent years' compliance to $5,000. There are
approximately 225 oil royalty payors on Indian leases. This equates to
$1,687,500 for all 225 payors to comply with the rule in the first year
and $1,125,000 in each subsequent year.
(3) Cost--Completing Form MMS-4416. Industry would also incur costs
to complete the proposed new information collection, Form MMS-4416.
Part of the Indian oil valuation comparison would rely on price indexes
that lessees may adjust for locational differences between the index
pricing point and the aggregation point. Indian land lessees and their
affiliates, as well as oil purchasers, would be required to give MMS
information on the location/quality differentials included in their
various oil exchange agreements and sales contracts. From this data MMS
would calculate and publish representative location/quality
differentials for lessees' use in reporting royalties in different
areas. Data from oil purchasers also would be used by MMS and Indian
personnel to verify royalty values and differentials reported on Form
MMS-2014.
We estimate the annual costs to industry to submit the Form MMS-
4416 to be $118,125. MMS estimates that, on average, a payor would have
six exchange agreements or sales contracts to dispose of the oil
production from the Indian lease(s) for which it makes royalty
payments. Compared to the February 12, 1998, proposal, we revised the
number of exchange agreements upward from three to six per payor based
on additional information from Indian lessors. We estimate that a payor
would need about one-half hour on average to gather the necessary
contract information and complete Form MMS-4416.
Filing Due to Contract Changes
We estimate the payor would have to submit the form twice a year
because of contract changes in addition to the required annual filing
discussed below.
225 payors x 6 agreements or contracts/payor x \1/2\ hour/
submission x 2 submissions/year = 1,350 burden hours
MMS estimates that in addition to the 1,350 agreements or contracts
submitted by payors, non-payor purchasers of crude oil from Indian
leases would also submit about half that amount (675 agreements or
contracts) as required by proposed Sec. 206.61(d)(5) (1998). Again, we
estimate that the filing of Form MMS-4416 would take 30 minutes per
report to gather the necessary documents and extract the data from
individual exchange agreements and sales contracts; we also estimate
that a non-payor purchaser would file a report twice a year for each
agreement/contract.
675 agreements or contracts x \1/2\ hour/submission x 2
submissions/year = 675 burden hours
Annual Filing
We would also require payors and non-payor purchasers to submit an
annual Form MMS-4416 for their agreements or contracts. The annual
filing requirement would assure Indian lessors, tribes and allottees
that all payors and non-payor purchasers are complying with these
proposed Indian valuation regulations. We estimate that this annual
filing would require 10 minutes per report to indicate a no-change
situation.
(1,350 + 675) agreements or contracts x 1 annual submission
x \1/6\ hour/submission = 337.5 burden hours
Total Filing Burden
Based on $50 per hour (revised upward from $35 per hour in our
February 12, 1998, analysis to better reflect current conditions), we
estimate the annual cost to industry in subsequent years would be
$118,125, computed as follows:
[[Page 407]]
(1,350 + 675 + 337.5 burden hours) x $50/hour = $118,125
(4) Cost--Filing Supplemental Report of Royalty and Remittance
(Form MMS-2014) with Major Portion Uplift. As mentioned earlier in the
provisions of the supplementary proposed rule, MMS would calculate a
major portion value specific to each tribe. This value would be based
on reported values on the Form MMS-2014. If the MMS-calculated value
were greater than what the lessee initially reported, they would have
to file a revised Form MMS-2014, and pay additional royalties.
Industry would incur an administrative burden from additional
filing of Form MMS-2014 lines to comply with the rule's major portion
provision. MMS analyzed reported royalty data for Indian leases for
1997. There were approximately 33,000 individual lines reported for oil
and about 6,000 lines for condensate on Form MMS-2014. We estimate that
if the proposed rule had applied to this production, there could have
been as many as 20,000 additional lines reported annually, or 1,667
lines monthly. This estimate is based on comparisons of the major
portion price with initially reported prices and replacing the original
price when the major portion price is higher. This estimate includes
backing out previously-reported lines and reporting new lines, or
effectively deleting and replacing up to 10,000 lines based on the
major portion calculations.
Electronic reporting accounts for about 80 percent of the lines
reported to MMS by lessees on Form MMS-2014. Thus there would have been
about 16,000 lines reported electronically. Based on an average of 2
minutes per line at a cost of $50 per hour, we estimate the
administrative burden would be $26,667 annually. MMS estimates that
there would have been 4,000 lines reported manually (20 percent of the
overall burden) and that this effort would stay the same in the future.
Based on an average of 7 minutes per line at $50 per hour, the
administrative burden for manual payors would be $23,333 annually. The
total estimated cost for filing additional Form MMS-2014 lines is
($26,667 + $23,333) = $50,000.
(5) Benefits--Administrative Savings. Industry would realize
administrative savings because of the reduced complexity in royalty
determination and payment in this proposed rule. Specifically, the
proposed rule would result in:
(i) Simplification of reporting and pricing, coupled with
certainty.
We anticipate that the proposed rule would significantly reduce the
time involved in the royalty calculation process. In the proposed
framework, the lessee would either report its gross proceeds or the
adjusted spot price applicable to its production. The need to work
through and apply the current benchmarks for non-arm's-length
transactions would be eliminated. Further, once MMS calculates a major
portion price, the lessee would compare this price to what they
reported and make adjustments as necessary.
It is difficult to quantify the amount of savings by simpler
reporting. The current level of time spent calculating royalties varies
greatly by company depending on many variables such as the complexity
of the disposition or sale of the product, the amount of production to
account for, and the computation of any necessary adjustments.
However, we assume that simpler reporting would save each payor at
least 30 minutes per month to report. This conservative figure amounts
to a reduction of 6 hours per year per payor for a savings of $300.
Over the 225 payors, this would amount to a total savings of $67,500
due to the reduced reporting burdens of the proposed rule.
(ii) Reductions in audit efforts.
When a company is audited, it incurs significant costs. It may be
required to gather records, provide documents, and in some cases
provide space and facility resources. Although these costs vary
significantly by company and by the nature of the audit, we believe
that cost savings at least as great as those for simplified reporting
would result.
The MMS audit tracking system indicates that approximately 500
Indian oil and gas leases had some type of audit work initiated in
1997. This estimate does not include leases that may have been audited
in 1997, but initiated in another year. Also, this figure does not
include company audits where auditors examined a sample of leases that
may have contained Indian leases. These 500 leases involved
approximately 100 companies. Although it is difficult to quantify the
future dollar savings for a similar sample of 100 companies, we believe
that the expected reduced audit burden would be a significant industry
benefit.
(iii) Reductions in valuation determinations and litigation.
The proposed rule would increase certainty for Indian royalty
payors. Payors would be assured that if they apply the adjustments
required by the proposed rule correctly and remit any additional monies
due under the major portion calculation, the amount they report likely
would be correct. Additionally, such payors would not be subject to
additional bills for additional royalties due with late-payment
interest attached. We expect that valuation disputes and requests for
valuation determinations would decrease significantly under the
proposed rule. Valuation determinations and disputes are very costly
for both industry and the Federal Government. Some statistics follow:
Over the last 10 years, MMS auditors identified more than
50,000 instances dealing with royalty underpayments for both oil and
gas from Federal and Indian lands. MMS resolved most of the issues
underlying the underpayments before the actual issuance of an order to
pay. In fact, MMS issued only 2,100 appealable orders during the same
period. Of those, 925 appeals resulted. These audit efforts resulted in
the collection of $1.16 billion in additional royalties that otherwise
would have gone uncollected. About 20 percent of MMS audit activity is
focused on Indian lands. Most Indian audits involve gas because
royalties for gas produced from Indian lands exceed oil by almost two-
to-one. However, the savings from reduced Indian oil audits would still
be substantial.
Over the past 10 years, Royalty Valuation Division (RVD)
Staff responded to over 5,000 separate requests by Federal and Indian
lessees for advice on valuation procedures and transportation/
processing allowances for royalty calculation purposes. These responses
resulted in 247 disputes (about 5 percent of all RVD responses) between
MMS and the payor over this same time period. These included disputes
over product value (131 separate issues) and allowances for
transportation or processing (116 separate issues).
The Department of the Interior Solicitor's Office reported
at least 47 separate cases since 1988 that they believed were
significant and involved valuation disputes.
Although it is extremely difficult to quantify the cost to both
industry and Government for all valuation disputes since 1988, it is
undoubtedly in the tens of millions of dollars. We conservatively
estimate that the proposed rule's certainty would reduce payors' legal
and other administrative costs on Indian leases by at least a million
dollars annually, or about $4,444 for each of the 225 payors.
Altogether, with the limited information we can collect and the
gross estimates we made, we assume a total savings to Indian oil lease
payors of approximately $1.1 million per year
[[Page 408]]
($67,500 in reporting savings, a similar amount for audit savings, and
$1 million in legal and administrative costs), or about $5,000 per
payor. This estimate is based on very conservative estimates where
actual data are difficult, if not impossible, to obtain. Actual savings
likely would be significantly higher.
b. State and Local Governments
------------------------------------------------------------------------
/benefit amount
Description ---------------------------------------
First year Subsequent years
------------------------------------------------------------------------
Cost--Increased Net Receipts 0 0
Sharing........................
------------------------------------------------------------------------
State net receipts sharing costs--that is, the MMS operating costs
deducted from a State's share of royalty revenue--would not change as a
result of this rule. MMS does not charge any portion of the costs of
administering Indian leases to States, including the increase in
administrative costs associated with this rule.
c. Indian Tribes and Allottees
------------------------------------------------------------------------
/benefit amount
Description ---------------------------------------
First year Subsequent years
------------------------------------------------------------------------
Benefit--Additional Mineral $4,667,510 $4,667,510
Revenues.......................
------------------------------------------------------------------------
We estimate that our proposed oil valuation regulations would
result in increased annual Indian oil royalties of approximately $4.7
million.
(1) Data Analyzed. MMS is revising its earlier estimate of $3.6
million that accompanied the February 12, 1998, proposed rule. The
original analysis associated with that proposal used data from 1995,
and concentrated on the three tribes receiving the majority of royalty
revenues. Then we extrapolated these results for the remaining tribes,
resulting in approximately $3.6 million in total gain for all the
tribes.
For the analysis associated with this supplementary proposed rule
we:
(i) Used 1997 data, because:
It is the last complete year for which all months of data
were available.
It represents a typical production year with no major
market interruptions.
It reflects data incorporating most of the edits and
corrections performed by the exception processing modules in MMS's
Auditing and Financial System and Production Accounting and Auditing
System.\1\
---------------------------------------------------------------------------
\1\ However, 1997 data are still unaudited and significant
adjustments may be made at a later date.
---------------------------------------------------------------------------
(ii) Analyzed, based on royalty revenues received, the top 12
Indian fund codes representing recipients of royalty revenues from
Indian lands \2\ because:
---------------------------------------------------------------------------
\2\ For purposes of this analysis, we used specific fund codes
to identify the impact of the rule. The top 12 fund codes represent
over 97% of oil royalties received on Indian lands in 1997. There
may be other fund codes that also are in some part related to the
top 12 codes. For example, the Witchita/Caddo Tribe (which was not
analyzed also receives funds from the Anadarko office.
---------------------------------------------------------------------------
This ensures that we have done a specific analysis for
each of the largest royalty recipients.
This allows us to apply the rule specifically to each fund
code, and analyze the impact. This also allows transportation and
quality adjustments specific to the oil and condensate produced at
particular locations.
The top 12 Indian oil and condensate fund code recipients
account for approximately 97 percent of all royalties received for all
Indian lands in 1997. These 12 fund codes are as follows:
Navajo (w/allottees)
Ute Indian Tribe(w/Allottees)
Shoshone/Arapaho (Wind River)(w/Allottees)
Alabama-Coushatta
Anadarko Agency Allotted
Muskogee Area Allotted
Shawnee Agency Allotted
Jicarilla Agency
Ft. Peck Tribal/Allotted
Cook Inlet Region Incorporated (CIRI)
Blackfeet (w/Allottees)
Ute Mountain Ute
(2) Determining Value. For the supplementary proposed Indian oil
valuation regulations, as stated earlier, MMS proposes to use the
greater of the following three calculations to determine value:
(i) Spot price-based value, adjusted for location differentials and
transportation costs.
Consistent with the provisions in the supplementary proposed rule,
one of the three valuation alternatives to be considered would be a
location-and quality-adjusted spot price. For all the above fund codes
(except CIRI), we used the spot price at Cushing, Oklahoma, for West
Texas Intermediate as reported in Platt's Oilgram. (In some cases the
Midland, Texas spot price may have been more appropriate, but the
actual estimates would vary little using the Midland spot price. This
fact, plus ease of administration, led us to use the Cushing value.)
For CIRI, we used the Alaska North Slope spot price as reported in
Platt's Oilgram.
As required by the proposed rule, we used the average of the daily
high spot prices for the trading month that corresponds to the
production month as a measure of value. For example, for the production
month of February, we used the average of the daily high spot prices
from December 26th through January 25th. The average consists of only
the business days within the trading month (typically 20 to 23 days).
We made adjustments to the spot price to arrive at a price that is
comparable to the oil value on the reservation. We made a separate
adjustment for both quality and location as follows:
Quality
Specific to each of the 12 fund codes, we calculated the weighted
average gravity reported for both oil and condensate for the entire
year. From this average, we made adjustments based on various posted
price adjustment scales in effect for the area to bring the Tribal oil
and condensate to 40 degrees API. This matches the specifications for
the West Texas Intermediate oil in Platt's Oilgram. In the case of
CIRI, we made adjustments to the 26.5 degree API Alaska North Slope
oil. We made specific individual adjustments to both oil and condensate
for each fund code; these products were not combined. In some cases,
the Indian fund code receives royalties on either oil or condensate,
but not both. (The calculations specific to each fund code
[[Page 409]]
contain proprietary data and are not included with this report.)
Location
We made location differential estimates specific to each fund code
based on Federal Energy Regulatory Commission (FERC) tariffs where
available. In most cases, a tariff exists between a collection point on
or very near the area represented by the fund code and Cushing,
Oklahoma. For the few cases where a tariff does not exist, we made an
estimate. We recognize that using these tariffs and estimates is
subject to some interpretation. The supplementary proposed rule
provides for locational information to be gathered via the proposed
Form MMS-4416. Once MMS solicits the information, we can calculate
differentials more accurately from the various aggregation points to
the spot market centers.
(ii) Actual gross proceeds received by the lessee or its affiliate.
We approximated gross proceeds accruing to lessees/affiliates by
querying MMS's Auditing and Financial System (AFS) database.\3\ For
both oil and condensate, we divided the reported total royalty value by
total royalty quantity to derive the gross proceeds unit value.
---------------------------------------------------------------------------
\3\ The AFS database does not contain all Indian records. Some
leases require special handling and are not entered in the database.
---------------------------------------------------------------------------
(iii) Major portion analysis at the 75 percent level.
Most Indian leases include a ``major portion'' provision, which
states that value should be the highest price paid or offered at the
time of production for the major portion of oil production from the
same field. Like the original proposed rule, the supplementary proposed
rule would require one of the three methods of valuation to be a major
portion calculation at the 75-percent level. Under the supplementary
proposed rule, MMS would calculate the monthly major portion value by
arraying sales and associated volumes reported on Form MMS-2014 from
lowest price to highest, and applying the price associated with the
sale where accumulated volumes exceed 75 percent of the total. In order
to calculate this value for the analysis, we used all oil and
condensate royalties reported for each fund code. For each month, we
arrayed the gross proceeds unit values from the lowest price to the
highest price to determine the value at which 75 percent plus one
barrel of the tribe's production was sold. We then multiplied this
``major portion'' price by the volumes below the 75-percent
``threshold'' to arrive at an incremental value attributable to the
major portion price. We performed this calculation for each month.
(3) Comparison of Values. For each month in 1997, we compared the
total fund code royalty value computed using each of the three
valuation methods discussed above. Consistent with the supplementary
proposed rule, we chose the highest of these values for each month in
1997 and calculated the increment over actual royalties reported. We
then summed these incremental values for both oil and condensate by
fund code. This grand total value became the estimated gain specific to
each fund code under the provisions of the supplementary proposed rule
as compared to actual royalties reported in 1997.
In most cases the spot price value was the highest of the three
values used in calculating the Indian royalty payment. We based our
estimates on the best data available and they may vary when we use
actual data. In some cases, the adjusted spot price was lower than the
major portion price. This occurred in some months for the Ute Indian
Tribe because the oil and condensate produced in the Uinta Basin have a
high paraffin or wax content. This high-paraffin crude generally
commands a premium over non-paraffin crude, is atypical in assay, and
is traded and used only in specialized markets. Further adjustments to
the spot price might be needed to better reflect paraffin's value
impact.
Typically, the additional royalty associated with the major portion
calculation increases based on the number of payors on the reservation.
We observed that for fund codes with few payors, little additional
royalty resulted from the major portion calculation. On the other hand,
when many payors reported, the additional royalty associated with the
major portion calculation increased.
(4) Projection of Gains to All Fund Codes. To estimate the total
annual dollar impact for all 32 fund codes that received royalties from
either oil or condensate in 1997, MMS used the combined dollar increase
calculated for each of the top 12 fund codes in terms of royalty
receipts. Royalties received by these 12 fund codes ($42,700,847)
represented 97.2325 percent of the total Indian oil and condensate
royalties actually collected in 1997. We estimate that total royalties
for the 12 fund codes would increase by about 10.6 percent or
$4,538,337 under the proposed rule. The distribution of this increase
among the 12 fund codes is shown in the table below.
------------------------------------------------------------------------
Navajo (w/Allottees)................................... $1,126,000.26
Ute Indian Tribe(w/Allottees).......................... 1,116,358.64
Shoshone/Arapaho(Wind River)(w/Allottees).............. 1,467,398.60
Alabama-Coushatta...................................... 76,098.33
Anadarko Agency Allotted............................... 131,748.84
Muskogee Area Allotted................................. 177,636.27
Shawnee Agency Allotted................................ 46,891.98
Jicarilla Agency....................................... 102,195.94
Ft. Peck Tribal/Allotted............................... 122,872.03
Cook Inlet Region Incorporated (CIRI).................. 44,142.74
Blackfeet (w/Allottees)................................ 92,187.54
Ute Mountain Ute....................................... 34,805.81
------------------------------------------------------------------------
We then projected the estimated increase for all Indian recipients,
as follows:
$4,538,337 X
------------- = --------
97.2325 100
------------------------------------------------------------------------
X = $4,667,510
We estimate that the total increase for all Indian royalty
recipients under the supplementary proposed rule would be $4,667,510.
d. Federal Government
------------------------------------------------------------------------
benefit amount
Description (see corresponding ---------------------------------------
narrative below) First year Subsequent years
------------------------------------------------------------------------
(1) Cost--Processing Form MMS- <$58,000> <$58,000>
4416...........................
(2) Cost--Calculating Major <324,000> <52,000>
Portion........................
(3) Benefit--Administrative 630,500 630,500
Savings........................
---------------------------------------
Net Benefit to Federal $248,500 $520,500
Government...............
------------------------------------------------------------------------
[[Page 410]]
(1) Cost--Processing Form MMS-4416. Processing Form MMS-4416 would
consist of two functions:
(i) Collecting data. We estimate we would require 160 hours
annually to collect, sort, and file the forms. Using an hourly cost of
$50, the annual cost would be $8,000 for this function.
(ii) Analyzing and publishing data. We estimate that we would
require 1,000 hours to analyze and publish the data gathered from the
Form MMS-4416's annually. This estimate includes the time spent
reviewing the data to verify royalty values and differentials reported
on Form MMS-2014. Using an hourly cost of $50, the annual cost of the
analysis would be $50,000.
(2) Cost--MMS Major Portion Value Calculations. In 1997, nine of
the fund codes used for distributing royalties to specific Indian
tribes and Allottee groups involved such limited royalty reporting that
an oil major portion analysis would have been meaningless. Separate
calculations would be required for condensate for some fund codes. MMS
estimates that oil major portion calculations would be needed for 23 of
these fund codes. Additionally, 7 of these 23 fund codes would require
condensate major portion calculations for a total of 30 separate major
portion calculations. Based on the number of lines reported per fund
code in 1997, the major portion calculations would be fairly simple for
some fund codes and fairly extensive for others. The distribution of
royalty lines reported for each of the 30 fund code/product (oil or
condensate) groups in 1997 supports this observation:
Over 1,000 lines: 12 fund code/product groups
100-1,000 lines: 12 fund code/product groups
Less than 100 lines: 6 fund code/product groups
MMS estimates that the initial set-up of the major portion
calculation would be the greatest burden. This set-up primarily would
involve researching the quality aspects of the crude oil and condensate
produced on Tribal and Allotted leases and writing the programming code
to calculate the major portion figures for each tribe or Allottee. Our
experience with major portion calculations for gas production provides
us with a basis for estimating the burden to MMS to administer the
major portion calculation for oil. We believe that initial set-up would
take an average of 400 hours for each fund code/product group with more
than 1,000 lines per annum (12 groups), an average of 120 hours for
each fund code/product group with more than 100 but less than 1,000
lines per annum (12 groups), and an average of 40 hours for each fund
code/product group with less than 100 lines per annum (6 groups). The
total set-up burden to MMS would then be 6,480 hours at a cost of $50
per hour or $324,000. Additionally, there would be an ongoing
administrative burden to MMS to perform the calculations each month and
update the programming code and quality aspects as production is added
or abandoned. There also would be administrative costs associated with
notifying the tribes and payors of the major portion calculations. This
cost is estimated to involve one-half of a full time employee's time at
an administrative burden of 1,040 hours per year at $50 per hour or
$52,000 per annum.
(3) Benefit--Administrative Savings. Additionally, MMS would
realize administrative savings because of reduced complexity in royalty
determination and payment under this proposed rule. Specifically, the
proposed rule would result in:
(i) Simplification of reporting and pricing, coupled with
certainty. MMS would continue to receive the same reports from the
payors that they currently submit. The only difference would be that
payors would need less time to calculate the royalty due under the
proposed rule. MMS would not realize any significant gains from the
reduction in the payor's reporting time.
MMS would realize some gains with the simplification of pricing and
the certainty involved. See discussion in paragraphs c (ii) and (iii)
below.
(ii) Reductions in audit efforts. Since the proposed rule would
eliminate use of the non-arm's-length benchmarks, the need for tedious
and complex audit work also would be eliminated. Currently, there are
48.5 full-time MMS and tribal employees working on Indian audit issues.
Using a figure of $50 per hour, this means that each year $5.044
million is spent on auditing all products on Indian properties.
According to the 1997 MMS Mineral Revenues report, Oil and Condensate
accounted for approximately 25 percent of the total Indian revenue
received in 1997. As a result, we assume that 25 percent of the audit
resources were directed to oil and condensate issues. This equates to
$1,261,000 per year in audit resources directed specifically to Indian
oil and condensate. Although some audit work still would need to be
performed to ensure compliance with the proposed rule, for estimation
purposes, we assume half of the total oil and condensate audit effort
would be eliminated, for a savings of $630,500.
(iii) Reductions in valuation determinations and litigation. As
discussed in section III.2(a)(5)(iii) of this preamble, MMS has been
engaged in significant litigation and dispute resolution over the past
10 years. It would be nearly impossible to estimate the total cost
related to these disputes and exactly how much the proposed rule would
save. It is not clear that MMS's fixed costs related to litigation
support would decrease under the proposed rule or, if so, how much.
3. Regulatory Planning and Review (E.O. 12866)
In accordance with the criteria in Executive Order 12866, this rule
is not an economically significant regulatory action. The Office of
Management and Budget (OMB) has made the determination under Executive
Order 12866 to review this rule because it raises novel legal or policy
issues.
a. This rule would not have an effect of $100 million or more on
the economy. It would not adversely affect in a material way the
economy, productivity, competition, jobs, the environment, public
health or safety, or State, local, or tribal governments or
communities.
b. This rule would not create serious inconsistencies with other
agencies' actions.
c. This rule would not materially affect entitlements, grants, user
fees, or loan programs or the rights or obligations of their
recipients.
d. This rule would raise novel legal or policy issues.
4. Regulatory Flexibility Act
The Department estimates that 173 small businesses would pay 30
percent of the $4.7 million dollar impact of the rule, or an additional
$1.4 million annually in royalties to the tribes and individual
Indians. This represents approximately 1.8 percent of the sales
revenues received by these companies from their Indian leases in 1997.
These 173 companies represent less than two percent of the
approximately 15,000 small oil and gas companies operating in the
United States. Nevertheless, because of the significant economic effect
on the 173 companies, MMS has, in this supplemental rulemaking,
proposed modifications that would to some extent mitigate the impact on
small businesses from the proposals under the February 12, 1998 rule.
For example, we are proposing to use spot prices instead of NYMEX
prices to simplify the computation of value and bring the valuation
point closer to the lease. We are also spreading the average of index-
based pricing from the highest
[[Page 411]]
five NYMEX prices for the production month to the average of all high
spot prices for the month. We are proposing to increase the
transportation deduction by allowing costs from the lease to the
reservation boundary. We are also proposing to simplify the Form MMS-
4416 and reduce the number of respondents that must submit the form.
Your comments are important. The Small Business and Agricultural
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
rule, call 1-888-734-4247.
5. Small Business Regulatory Enforcement Act (SBREFA)
This rule is not a major rule under 5 U.S.C. 804(2), the Small
Business Regulatory Enforcement Fairness Act. This rule:
a. Would not have an annual effect on the economy of $100 million
or more.
b. Would not cause a major increase in costs or prices for
consumers, individual industries, Federal, State, or local government
agencies, or geographic regions.
c. Would not have significant adverse effects on competition,
employment, investment, productivity, innovation, or the ability of
U.S.-based enterprises to compete with foreign-based enterprises.
6. Unfunded Mandates Reform Act
This rule would not impose an unfunded mandate on State, local, or
tribal governments or the private sector of more than $100 million per
year. Because this rule affects only Indian leases, the rule would not
have a significant or unique effect on State or local governments.
Because royalties would increase for these leases, it would have a
beneficial effect on tribal governments. A statement containing the
information required by the Unfunded Mandates Reform Act (2 U.S.C. 1531
et seq.) is not required.
7. Takings (E.O. 12630)
In accordance with Executive Order 12630, the rule would not have
significant takings implications. This rule would not impose conditions
or limitations on the use of any private property; consequently, a
takings implication assessment is not required.
8. Federalism (E.O. 13132)
In accordance with Executive Order 13132, this supplementary
proposed rule does not have Federalism implications. This rule does not
substantially and directly affect the relationship between the Federal
and State governments. This rule does not impose costs on States or
localities. This rule does not preempt State law. As stated above, this
rule affects only tribal governments.
9. Civil Justice Reform (E.O. 12988)
In accordance with Executive Order 12988, the Office of the
Solicitor has determined that this rule would not unduly burden the
judicial system and would not meet the requirements of sections 3(a)
and 3(b)(2) of the Order.
10. Paperwork Reduction Act of 1995
Under the Paperwork Reduction Act of 1995, we are soliciting
comments on an information collection titled Indian Crude Oil Valuation
Report, Form MMS-4416, OMB Control Number 1010-0113, expiration date
April 30, 2001, which is associated with this supplementary proposed
rulemaking. The proposed rule references two other information
collections: Report of Sales and Royalty Remittance, Form MMS-2014, OMB
1010-0022; and Oil Transportation Allowance, Form MMS-4110, OMB 1010-
0061. However, in this proposed rule we are only soliciting comments on
the Indian Crude Oil Valuation Report.
The PRA 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. OMB is
required to make a decision concerning the collection of information
contained in these proposed regulations between 30 to 60 days after
publication of this document in the Federal Register. Therefore, a
comment to OMB is best assured of having its full effect if OMB
receives it by February 4, 2000. This does not affect the deadline for
the public to comment to MMS on the proposed regulations.
You may submit comments directly to the Office of Information and
Regulatory Affairs, OMB, Attention: Desk Officer for the Interior
Department (OMB Control Number 1010-0113), 725 17th Street, NW,
Washington, DC 20503 [telephone (202) 395-7340]. You should also send
copies of these comments to us.
Section 3506(c)(2)(A) of the Paperwork Reduction Act requires each
agency ``to provide notice * * * and otherwise consult with members of
the public and affected agencies concerning each proposed collection of
information.* * * '' Agencies must specifically solicit comments to:
(a) Evaluate whether the proposed collection of information is
necessary for the agency to perform its duties, including whether the
information is useful; (b) evaluate the accuracy of the agency's
estimate of the burden of the proposed collection of information; (c)
enhance the quality, usefulness, and clarity of the information to be
collected; and (d) minimize the burden on the respondents, including
the use of automated collection techniques or other forms of
information technology.
We received a number of comments that the data requirements for
completing Form MMS-4416 were too burdensome and the resultant MMS
location differential calculations would not be reliable. We do not
agree that the calculation of differentials from Form MMS-4416 data
would not be reliable. However, in response to comments received, we
streamlined Form MMS-4416 by eliminating and/or simplifying certain
data requirements and clarifying the instructions included with the
form. In addition to revising/clarifying the instructions, the
supplementary proposed rule proposes to change lessees' submission
requirements on Form MMS-4416 to data related to crude oil production
from Indian leases in designated areas rather than all production from
designated areas. These changes will aid respondents in complying with
the requirements of this information collection and still permit MMS to
acquire the information needed to calculate relevant location
differentials and verify royalty values and differentials reported on
Form MMS-2014.
We have revised the approved information collection, OMB Control
Number 1010-0113, according to the supplementary proposed rulemaking
and to be responsive to comments received. We estimate the total annual
burden for this information collection is approximately 2,363 hours, an
increase over the current OMB inventory of 1,050 hours. Although we
have revised and streamlined the forms and clarified the instructions,
we still estimate the time to complete Form MMS-4416 is \1/2\ hour,
and, therefore, there is no increase in hours associated with the
program change for this collection. However, we have revised our
estimate of the number of respondents upward from 125 oil royalty
payors to 225 payors; this is an adjustment of 1,050 hours.
[[Page 412]]
11. National Environmental Policy Act
This rule would not constitute a major Federal action significantly
affecting the quality of the human environment. A detailed statement
under the National Environmental Policy Act of 1969 is not required.
12. Clarity of This Regulation
Executive Order 12866 requires each agency to write regulations
that are easy to understand. We invite your comments on how to make
this rule easier to understand, including answers to questions such as
the following: (1) Are the requirements in the rule clearly stated? (2)
Does the rule contain technical language or jargon that interferes with
its clarity? (3) Does the format of the rule (grouping and order of
sections, use of headings, paragraphing, etc.) aid or reduce its
clarity? (4) Would the rule be easier to understand if it were divided
into more (but shorter) sections? (A ``section'' appears in bold type
and is preceded by the symbol ``Sec. '' and a numbered heading; for
example, ``Sec. 206.61 How do lessees determine transportation
allowances and other adjustments?'' (5) Is the description of the rule
in the ``Supplementary Information'' section of the preamble helpful in
understanding the proposed rule? What else could we do to make the rule
easier to understand?
Send a copy of any comments that concern how we could make this
rule easier to understand to: Office of Regulatory Affairs, Department
of the Interior, Room 7229, 1849 C Street NW, Washington, DC 20240. You
may also e-mail the comments to this address: Exsec@ios.doi.gov.
List of Subjects in 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: December 3, 1999.
Sylvia Baca,
Acting Assistant Secretary, Land and Minerals Management.
For the reasons set forth in the preamble, 30 CFR Part 206 is
proposed to be amended as follows:
PART 206--PRODUCT VALUATION
1. The Authority citation for part 206 continues to read as
follows:
Authority: 5 U.S.C. 301 et seq.; 25 U.S.C. 396 et seq., 396a et
seq., 2101 et seq.; 30 U.S.C. 181 et seq., 351 et seq., 1001 et
seq., 1701 et seq.; 31 U.S.C. 9701, 43 U.S.C. 1301 et seq., 1331 et
seq., and 1801 et seq.
Subpart B--Indian Oil
2. Section 206.51 is amended by adding the definitions of Index
pricing, MMS-approved publication Aggregation point, and Rocky Mountain
Region as follows:
Sec. 206.51 Definitions.
* * * * *
Aggregation point means a central point where production is
aggregated for shipment to market centers or refineries. It includes,
but is not limited to, blending and storage facilities and connections
where pipelines join. Pipeline terminations at refining centers also
are classified as aggregation points. MMS will publish periodically in
the Federal Register a list of aggregation points and associated market
centers.
* * * * *
Index pricing means using spot prices for royalty valuation.
* * * * *
MMS-approved publication means a publication MMS approves for
determining spot prices.
* * * * *
Rocky Mountain Region means the States of Colorado, Montana, North
Dakota, South Dakota, Utah, and Wyoming.
* * * * *
3. Section 206.52 is revised to read as follows:
Sec. 206.52 How does a lessee determine the royalty value of the oil?
This section explains how you must determine the value of oil
produced from Indian leases. For royalty purposes, the value of oil
produced from leases subject to this subpart is the value calculated
under this section with applicable adjustments determined under this
subpart. The following table lists three oil valuation methods. You
must determine the value of oil using the method that yields the
highest value. As explained under paragraph (d) of this section, you
must select from the first two methods and make an initial value
calculation and payment based on the method that yields the highest
value. MMS will calculate and publish the value under the third method.
If the third method yields a higher value than the first two methods,
you must adjust the value from your initial calculation as explained
under paragraph (d) of this section.
------------------------------------------------------------------------
Valuation method Subject to
------------------------------------------------------------------------
The average of the daily high spot prices for Paragraphs (a)(1)-(5) of
deliveries during the production month for this section.
the market center nearest your lease for
crude oil most similar in quality to your
oil.
The gross proceeds from the sale of your oil Paragraphs (b)(1)-(4) of
under an arm's-length contract. this section.
A major portion value that MMS calculates for Paragraphs (c)(1)-(4) of
each designated area and publishes in the this section.
Federal Register.
------------------------------------------------------------------------
(a) Calculate the average daily high spot price for deliveries
during the production month for the crude oil most similar in quality
to your oil at the market center nearest your lease where spot prices
are published in an MMS-approved publication by averaging the daily
high spot prices for the month in the selected publication. Use only
the days and corresponding high spot prices for which such prices are
published.
(1) For leases within the Rocky Mountain Region the appropriate
market center is at Cushing, Oklahoma.
(2) You must adjust the index price for applicable location and
quality differentials under Sec. 206.61(c) of this subpart.
(3) If applicable, you may adjust the index price for
transportation costs under Sec. 206.61(c) of this subpart.
(4) If you dispose of oil under an exchange agreement and you
refine rather than sell the oil that you receive in return, you must
use this paragraph (a) to determine initial value. Do not use paragraph
(b) of this section.
(5) MMS will monitor the spot prices. If MMS determines that spot
prices are unavailable or no longer represent reasonable royalty value,
MMS will amend this section to establish a substitute valuation method.
(6) MMS periodically will publish in the Federal Register a list of
approved spot price publications based on certain criteria, including
but not limited to:
(i) Publications that buyers and sellers frequently use;
(ii) Publications frequently mentioned in purchase or sales
contracts;
(iii) Publications that use adequate survey techniques, including
development of spot price estimates
[[Page 413]]
based on daily surveys of buyers and sellers of crude oil; and
(iv) Publications independent from MMS, other lessors, and lessees.
(7) Any publication may petition MMS to be added to the list of
acceptable publications.
(8) MMS will specify the tables you must use in the publications to
determine the associated spot prices.
(b) You may calculate value using the gross proceeds from the sale
of your oil under an arm's-length contract. If you use this method, the
provisions of this paragraph (b) apply.
(1) You may adjust the gross proceeds-based value calculated under
this section for appropriate transportation costs under Sec. 206.61(c)
of this subpart.
(2) If you dispose of your oil under an exchange agreement and then
sell the oil that you receive in return under an arm's-length contract,
value is the sales price adjusted for appropriate quality differentials
and transportation costs.
(3) MMS may monitor, review, or audit the royalty value that you
report under this paragraph (b).
(i) MMS may examine whether your oil sales contract reflects the
total consideration actually transferred either directly or indirectly
from the buyer to you. If it does not, then MMS may require you to
value the oil sold under that contract at the total consideration you
received.
(ii) MMS may require you to certify that the arm's-length contract
provisions include all of the consideration the buyer must pay, either
directly or indirectly, for the oil.
(4) You must base value on the highest price that you can receive
through legally enforceable claims under your oil sales contract. If
you fail to take proper or timely action to receive prices or benefits
you are entitled to, you must base value on that obtainable price or
benefit.
(i) In some cases you may apply timely for a price increase or
benefit allowed under your oil sales contract, but the purchaser
refuses your request. If this occurs, and you take reasonable
documented measures to force purchaser compliance, you will owe no
additional royalties unless or until you receive monies or
consideration resulting from the price increase or additional benefits.
This paragraph (b)(4) does not permit you to avoid your royalty payment
obligation if a purchaser fails to pay, pays only in part, or pays
late.
(ii) Any contract revisions or amendments that reduce prices or
benefits to which you are entitled must be in writing and signed by all
parties to your arm's-length contract.
(c) You may use a major portion value that MMS will calculate. If
you use this method, the provisons of this paragraph apply.
(1) MMS will calculate the major portion value for each designated
area and notify lessees by publishing these values in the Federal
Register.
(2) Each designated area includes all Indian leases in that area.
MMS will publish in the Federal Register a list of the leases in each
designated area. The designated areas are:
(i) Alabama-Coushatta;
(ii) Blackfeet Reservation;
(iii) Crow Reservation;
(iv) Fort Belknap Reservation;
(v) Fort Peck Reservation;
(vi) Jicarilla Apache Reservation;
(vii) MMS-designated groups of counties in the State of Oklahoma;
(viii) Michigan Agency;
(ix) Navajo Reservation;
(x) Northern Cheyenne Reservation;
(xi) Southern Ute Reservation;
(xii) Turtle Mountain Reservation;
(xiii) Ute Mountain Ute Reservation;
(xiv) Uintah and Ouray Reservation;
(xv) Wind River Reservation; and
(xvi) Any other area that MMS designates. MMS will publish any new
area designations in the Federal Register.
(3) MMS will calculate the major portion value from information
submitted for production from leases in the designated area on Form
MMS-2014, Report of Sales and Royalty Remittance.
(i) MMS will use information from Form MMS-4416, Indian Crude Oil
Valuation Report, to verify values reported on Form MMS-2014. See
Sec. 206.61(d)(5) of this subpart for further requirements related to
Form MMS-4416.
(ii) MMS will arrange the reported values (adjusted for location
and quality) from highest to lowest. The major portion value is the
value of the 75th percentile (by volume, including volumes taken in
kind) starting from the lowest value.
(4) MMS will not change the major portion value after it publishes
that value in the Federal Register, unless an administrative or
judicial decision requires MMS to make a change.
(d) On Form MMS-2014, you must initially report and pay the value
of production at the higher of the index-based or gross proceeds-based
values determined under paragraph (a) or (b) of this section,
respectively. You must file this report and pay MMS by the date royalty
payments are due for the lease. MMS will inform you of its calculated
major portion value for the designated area by publishing that value in
the Federal Register. If this value exceeds the value you initially
reported for the production month, you must submit an amended Form MMS-
2014 with the higher value within 30 days after MMS publishes the major
portion value in the Federal Register. MMS will specify, in the MMS Oil
and Gas Payor Handbook, additional requirements for reporting under
paragraph (a), (b), or (c) of this section. You will not begin to
accrue late-payment interest under 30 CFR 218.54 on any underpayment
based on any additional amount owed as a result of the higher major
portion value until the due date of your amended Form MMS-2014.
4. Section 206.54 is redesignated as Sec. 206.60 and revised to
read as follows:
Sec. 206.60 What transportation allowances and other adjustments apply
to the value of oil?
(a) Transportation allowances. (1) You may deduct a transportation
allowance from the value of oil determined under Sec. 206.52 of this
part as explained in the following table.
See Sec. 206.61(a) and (b) for information on how to determine the
transportation allowance.
------------------------------------------------------------------------
If you value oil Then
------------------------------------------------------------------------
Based on index pricing under You may claim a transportation allowance
Sec. 206.52(a). only under the limited circumstances
listed at Sec. 206.61(c)(2).
Based on gross proceeds under MMS will allow a deduction for the
Sec. 206.52(b) and the reasonable, actual costs to transport
movement of the oil is not oil from the lease or unit to the sales
gathering. point.
------------------------------------------------------------------------
(2) You may not deduct a transportation allowance for transporting
oil:
(i) Taken as royalty in kind and delivered to the lessor in the
designated area; or
(ii) When you value oil based on a major portion value under
Sec. 206.52(c)
[[Page 414]]
(b) Are there limits on my transportation allowance?
(1) Except as provided in paragraph (b)(2) of this section:
------------------------------------------------------------------------
If you determine the value of Then your transportation allowance
the oil based on deduction may not exceed
------------------------------------------------------------------------
Index pricing under Sec. 50 percent of the average daily high spot
206.52(a). prices for the delivery month for the
applicable market center.
Gross proceeds under Sec. 50 percent of the value of the oil at the
206.52(b). point of sale.
------------------------------------------------------------------------
(2) You may ask MMS to approve a transportation allowance deduction
in excess of the limitation in paragraph (b)(1) of this section. You
must demonstrate that the transportation costs incurred were
reasonable, actual, and necessary. Your application for exception
(using Form MMS-4393, Request to Exceed Regulatory Allowance
Limitation) must contain all relevant supporting documentation
necessary for MMS to make a determination. You may never reduce the
royalty value of any production to zero.
(c) Must I allocate transportation costs? You must allocate
transportation costs among all products produced and transported as
provided in Sec. 206.61 of this subpart. You may not allocate
transportation costs from production for which those costs were
incurred to production for which those costs were not incurred. You
must express transportation allowances for oil as dollars per barrel.
(d) What other adjustments apply when I value production based on
index pricing? If you value oil based on index pricing under
Sec. 206.52(a), you must adjust the value for the differences in
location and quality between oil at the lease and the index pricing
point as specified under Sec. 206.61(c). See Sec. 206.61 for more
information on adjusting for location and quality differences.
(e) What additional payments may I be liable for? If MMS determines
that you underpaid royalties because an excessive transportation
allowance or other adjustment was claimed, then you must pay any
additional royalties, plus interest under 30 CFR 218.54. You also could
be entitled to a credit with interest if you understated the
transportation allowance or other adjustment. If you take a deduction
for transportation on Form MMS-2014 by improperly netting the allowance
against the sales value of the oil instead of reporting the allowance
as a separate line item, MMS may assess you an amount under
Sec. 206.61(e) of this subpart.
5. Section 206.55 is redesignated as section 206.61 and is amended
by revising the section heading; removing paragraphs (b)(5) and
(c)(2)(viii); redesignating paragraphs (c) through (g) as paragraphs
(d) through (h); adding new paragraphs (c) and (d)(5); and revising
newly redesignated paragraphs (d)(1)(i), (d)(2)(i), (d)(4) to read as
follows:
Sec. 206.61 How do lessees determine transportation allowances and
other adjustments?
* * * *
(c) What adjustments apply when lessees use index pricing?
(1) When you use index pricing to calculate the value of production
under Sec. 206.52(a), you must adjust the index price for location/
quality differentials. Your adjustments must reflect the reasonable oil
value differences in location and quality between the lease and the
index pricing point. The adjustments that might apply to your
production are listed in paragraphs (c)(1)(i) through (v) of this
section. See paragraphs (c)(2) and (c)(3) of this section to determine
which adjustments you must use based on how you dispose of your
production. These adjustments are:
(i) An express location/quality differential under your arm's-
length exchange agreement that reflects the difference in value of
crude oil at the market center and the aggregation point.
(ii) A location/quality differential reflecting the crude oil value
difference between the market center and the aggregation point that MMS
will publish annually based on data it collects on Form MMS-4416. MMS
will calculate each differential using a volume-weighted average of the
differentials reported on Form MMS-4416 for similar quality crude oils
for the aggregation point/market center pair for the previous reporting
year. MMS may exclude apparent anomalous differentials from that
calculation. MMS will publish separate differentials for different
crude oil qualities that are identified separately on Form MMS-4416
(for example, sweet versus sour or different gravity ranges). MMS will
publish these differentials in the Federal Register by [the effective
date of the final regulation] and by January 31 of all subsequent
years. You must use MMS-published rates on a calendar year basis--apply
them to January through December production reported February through
the following January.
(iii) Actual transportation costs between the aggregation point and
the lease or unit determined under this section.
(iv) Actual transportation costs between the market center and the
lease or unit determined under this section.
(v) Quality adjustments based on premia or penalties determined by
pipeline quality bank specifications at intermediate commingling
points, at the aggregation point, or at the market center that applies
to your lease.
(2) To determine which adjustments and transportation allowances
apply to your production, use the following table.
------------------------------------------------------------------------
If you And Then
------------------------------------------------------------------------
Dispose of your production That exchange Adjust your value
under an arm's-length agreement has an using paragraph
exchange agreement. express location (c)(1)(i).
differential to
reflect the
difference in
value between
the aggregation
point and the
associated
market center.
Move your production from a ................. Use paragraph
lease directly to an MMS- (c)(1)(v) to
identified market center. determine the
quality adjustment
and paragraph
(c)(1)(iv) to deduct
the actual
transportation costs
to that market
center.
[[Page 415]]
Do not move your production You instead move Use paragraph
from a lease to an MMS- it directly to (c)(1)(v) to
identified market center. an alternate determine the
disposal point quality adjustment
(for example, and paragraph
your own (c)(1)(iii) to
refinery). deduct the actual
transportation costs
to the alternate
disposal point.
Treat the alternate
disposal point as
the aggregation
point to apply
paragraph
(c)(1)(iii).
Transport or dispose of your ................. Adjust your value
production under any other using paragraphs
arrangement. (c)(1)(ii),
(c)(1)(iii), and
(c)(1)(v).
------------------------------------------------------------------------
(3) If an MMS-calculated differential under paragraph (c)(1)(ii) of
this section does not apply to your oil, either due to location or
quality differences, you must request MMS to calculate a differential
for you.
(i) After MMS publishes its annual listing of location/quality
differentials, you must file your request in writing with MMS for an
MMS-calculated differential.
(ii) You must demonstrate why the published differential does not
adequately reflect your circumstances.
(iii) MMS will calculate such a differential when it receives your
request or when it discovers that the differential published under
paragraph (c)(1)(ii) of this section does not apply to your oil. MMS
will bill you for any additional royalties and interest due. If you
file a request for an MMS-calculated differential within 30 days after
MMS publishes its annual listing of location/quality differentials, the
calculated differential will apply beginning with the effective date of
the published differentials. Otherwise, the MMS-calculated differential
will apply beginning the first day of the month following the date of
your application. In that event, the published differentials will apply
in the interim and MMS will not refund any overpayments you made due to
your failure to timely request MMS to calculate a differential for you.
(iv) Send your request to: Minerals Management Service, Royalty
Management Program, Royalty Valuation Division, P.O. Box 25165, Mail
Stop 3150, Denver, CO 80225-0165.
(4) Periodically, MMS will publish in the Federal Register a list
of market centers. MMS will monitor market activity and, if necessary,
modify the list of market centers and will publish such modifications
in the Federal Register. MMS will consider the following factors and
conditions in specifying market centers:
(i) Points where MMS-approved publications publish prices useful
for index purposes;
(ii) Markets served;
(iii) Pipeline and other transportation linkage;
(iv) Input from industry and others knowledgeable in crude oil
marketing and transportation;
(v) Simplification; and
(vi) Other relevant matters.
(d) Reporting requirements--(1) Arm's-length contracts. (i) With
the exception of those transportation allowances specified in
paragraphs (d)(1)(v) and (d)(1)(vi) of this section, you must submit
page one of the initial Form MMS-4110 (and Schedule 1), Oil
Transportation Allowance Report, before, or at the same time as, you
report the transportation allowance determined under an arm's-length
contract on Form MMS-2014, Report of Sales and Royalty Remittance. A
Form MMS-4110 received by the end of the month that the Form MMS-2014
is due is considered to be timely received.
* * * * *
(2) Non-arm's-length or no contract. (i) With the exception of
those transportation allowances specified in paragraphs (d)(2)(v) and
(d)(2)(vii) of this section, you must submit an initial Form MMS-4110
before, or at the same time as, you report the transportation allowance
determined under a non-arm's-length contract or no-contract situation
on Form MMS-2014. A Form MMS-4110 received by the end of the month that
the Form MMS-2014 is due is considered to be timely received. The
initial report may be based upon estimated costs.
* * * * *
(4) What additional requirements apply to Form MMS-2014 reporting?
You must report transportation allowances, location differentials, and
quality differentials as separate lines on Form MMS-2014, unless MMS
approves a different reporting procedure. MMS will provide additional
reporting details and requirements in the MMS Oil and Gas Payor
Handbook.
(5) What information must lessees provide to support index pricing
adjustments, and how is it used? You must submit information on Form
MMS-4416 related to all of your crude oil production from Indian
leases. You initially must submit Form MMS-4416 no later than [insert
the date 2 months after the effective date of this rule] and then by
October 31 [insert the year this regulation takes effect], and by
October 31 of each succeeding year. In addition to the annual
requirement to file this form, you must file a new form each time you
execute a new exchange or sales contract involving the production of
oil from an Indian lease. However, if the contract merely extends the
time period a contract is in effect without changing any other terms of
the contract, this requirement to file does not apply. All other
purchasers of crude oil from designated areas likewise are subject to
the requirements of this paragraph (d)(5).
* * * * *
Note: The following attachments will not appear in the Code of
Federal Regulations.
BILLING CODE 4310-MR-P
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[[Page 417]]
[GRAPHIC] [TIFF OMITTED] TP05JA00.001
BILLING CODE 4310-MR-C
[[Page 418]]
Step-by-Step Instructions for MMS Form 4416
This form is designed to collect valuation and location/quality
differential information about oil produced from Indian and allotted
leases to determine its market value. You should fill out this form if
you produce, sell, purchase, exchange, or refine oil produced from
Indian lands. A separate form should be used for each contract. If a
contract refers to more than one lease, one form may be filled out
provided a list of leases it covers is attached.
1. Company (Reporter) Information
Fill out your company name and address. Indicate whether the
contract you are reporting on applies to more than one lease by marking
the box in the upper right corner. If more than one form is needed to
provide the required information (e.g., multiple-party exchange
agreement), the address may be omitted from subsequent forms provided
that the cover form containing your address is attached.
--Write in the reporting period this form covers in the following
format: MM, YYYY.
--Write in the name of the Designated Area from which the oil
production on this form originates (a list of leases found in each
Designated Area will be published in the Federal Register).
--Enter your five-digit MMS payor code on each form submitted (if your
company does not have a payor code MMS will assign one).
Mark the ``Attached Page Provided'' box provided if any information is
contained on an attached page.
2. Contract Type
Mark the appropriate box to indicate the contract type. [Outright
Purchases are made at arm's-length and no additional consideration is
paid (in this transaction or in any other transaction). Buy/Sell is an
exchange where monetary value is assigned to settle both transactions
in the exchange. No-Price Exchange is a transaction where no monetary
value is assigned to either transaction in the exchange; instead, a
dollar amount is usually assigned to the difference between the two
values. Sales Subject to Balancing are transactions tied to an overall
exchange agreement (either expressed or implied) where volumes
purchased and sold by each party are in balance. Outright Sales are
made at arm's-length and no additional consideration is received (in
this transaction or in any other transaction). If this oil transaction
is part of a multiple-party (three or more) exchange agreement, check
the box to the right of the contract number titled Multiple-Party
Exchange].
Also fill in the Contract Number--use the I.D. that would allow a
third party to clearly identify the document.
3. Other Contract Party Name
Write the name of the other party to the contract involving the
Indian oil. If that party has an MMS payor code, write it in the space
provided (if known). If the transaction is part of a multiple-party
exchange, attach a list of the other parties involved in the exchange
(write their MMS payor code, if known, next to each party's name).
4. Contract Term
Note: If you are filing this contract to satisfy the annual Oct.
31 reporting requirement and none of the required entries in steps
4-9 have changed from the last report (filed in the last 12 months),
check the box in the lower left corner of section 4. If no change
has occurred except to extend the expiration date of the contract,
check the box in the lower left corner of section 4 and fill in the
new expiration date in this section. Make sure that an authorized
representative signs and dates the form. Otherwise complete the form
as instructed below).
In the Effective Date field, fill in the date the contract started,
and fill out the Initial Term in months. Check the contract term that
applies to this contract (either Month-to-Month Extensions or Fixed
Duration). If the contract is of fixed duration, fill in the Expiration
Date in the space provided.
Items 5-8
The information on the rest of the form is divided into two
columns. The left column should be used to record information about oil
you produced and either sold, transferred in an exchange or buy/sell,
or refined. The right column should be used for oil that you purchased
or you received in an exchange or buy/sell (i.e., you will use both
columns for oil that is part of an exchange agreement, and you will use
one column for oil you produced and refined, produced and sold outright
or purchased outright).
5. Title Transfer Location
In the space provided, write the location where you relinquished
title to the oil you sold or transferred and/or where you took title to
oil you purchased or received under an exchange. Where title
transferred at the lease, write ``at the lease'' and the 10-digit MMS
lease number (if the title transfer involves production from more than
one Indian lease, provide the list of the leases contributing to the
production). If the transfer occurs at an aggregation point or market
center indicate its name.
If you (or your affiliate) refine the oil you produce, write the
words ``producer refines its oil'' in the space adjacent to the
``Location of Transfer'' (note: you will not have to complete section
7, ``Pricing Terms'' if you refine oil you produce from Indian or
allotted lands).
In the space provided after ``Cost of Transporting to Title
Transfer Point,'' fill in the $/barrel cost of transporting oil you
produced from the production location to the point where title
transfers (do not include the cost of gathering). Likewise, for oil you
received, fill in the transportation cost if known. Describe the terms
(i.e. starting location, ending location) involved in transporting the
oil. Use Designated Areas (as defined at 30 CFR 206.51 and listed at 30
CFR 206.52(c)(2)), Aggregation Points (as defined at 30 CFR 206.51), or
State, Section/Township/Range. Where oil traverses more than one MMS
Aggregation Point be sure to include all segments of the transportation
route. Attach a separate sheet, if needed, to adequately describe the
transportation.
6. Volume Terms
If your contract states that all available oil will be purchased,
mark the All Available box and write in the estimated barrels per day
of oil disposed or received. Otherwise, check the Fixed box and write
in the fixed volume disposed of or received as specified in the
contract.
7. Pricing Terms
This section pertains to information about price received (or paid)
in arm's-length sales (or purchases) of crude oil produced from Indian
or allotted lands. If this oil is part of a buy/sell exchange, report
the price terms stated in the contract. For any exchange, the
differential should be reported in section 9.
If you purchase or sell oil production from Indian or allotted
lands: If the contract references a Posted Price, mark the box provided
and write in the name(s) of the company or companies posting(s) under
``Posting Company Name(s).'' If the crude oil type is designated (e.g.
sweet or sour), write this in the space labeled ``Poster's Crude Type/
Designation.'' List any Premium (+) to or deduction (-) from the
referenced price(s).
Other: describe the pricing method used.
Index Price: If an index price is used, identify it and the source
publication(s) in the space provided.
[[Page 419]]
Calculated Price: If the contract uses a formula to determine
price, completely describe the method used. Attach an additional sheet
if necessary.
Fixed Price: If the price is set through the duration of the
contract, list the price per barrel.
If the pricing terms are not covered under any of the above pricing
provisions, describe the pricing term used in the space provided.
Attach an additional sheet if necessary.
8. Crude Oil Quality and Adjustments
Quality Measures: Fill in the API Gravity of oil disposed of and/or
received to the nearest tenth of a degree. Fill in the Sulfur Content
of the oil you disposed of and/or received to the nearest tenth of a
percent. Fill in the Paraffin Content of the oil you disposed of and/or
received to the nearest tenth of a percent.
Adjustments: Fill in this information only where the contract
specifically identifies separate adjustments with a monetary value
assigned to each adjustment.
API Gravity: Check the appropriate box. If the gravity is
``Deemed,'' write the deemed API gravity to the nearest tenth of a
degree and any corresponding price adjustment from the contract. If an
``Actual'' reference gravity is used to make an adjustment, write the
gravity to the nearest tenth of a degree and any corresponding price
adjustment from the contract.
Other Quality Adjustment(s): Space is provided for up to two other
quality adjustments. Use the spaces provided in this section to
describe additional quality adjustments. Indicate whether the measure
is ``Actual'' or ``Deemed,'' and the dollar-per-barrel adjustment for
the quality measure. If your contract contains more than two other
quality adjustments, check the ``More than two'' box and attach a
separate sheet to fully describe the quality adjustments. Indicate the
type of adjustment and whether the quality measured is ``Actual'' or
``Deemed.'' Also, provide the adjustment amount in dollars per barrel
for each adjustment made.
9. Exchange Differential
This section requests information about the differential received
or paid by you under an exchange agreement. Only complete this section
if the contract you are reporting on is an exchange agreement.
If oil produced from Indian tribal or allotted lands is either
transferred or received by you in an exchange:
In exchanges where two separate volumes of oil were exchanged
between the two parties to the exchange contract, there may be a
differential paid by the party who exchanges oil considered to be worth
less than the oil it receives. This may result from relative location
advantages, or quality differences between the oils.
If your purpose under an exchange was to transport your oil on
another party's pipeline, the payment will reflect the cost of service
to transport your oil. This type of transaction is not considered an
exchange for purposes of this information collection but should be
included in ``Title Transfer Location'' section 5, above. Any separate
adjustments that were made to reflect gravity or sulfur content of your
oil will be addressed in section 9 below.
If a differential is paid or received by you or your affiliate,
write the total of any differential payment you received, (+) or the
total of any differential payment you made (-) under the exchange
agreement in the space provided.
Authorized Signature: Have you received or paid additional
consideration? If you have received or paid consideration other than
that shown on the form, check the ``yes'' box and provide an
explanation in the space provided. If the form accurately reports all
the compensation you received or paid for oil reported on this form,
check ``no.'' An individual authorized to represent the party to the
contract you are summarizing must sign the form. Write the date the
form was completed in the space provided.
[FR Doc. 00-58 Filed 1-4-00; 8:45 am]
BILLING CODE 4310-MR-P
