[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]


=======================================================================
-----------------------------------------------------------------------

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.

-----------------------------------------------------------------------

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.[email protected]. 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.[email protected].

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

------------------------------------------------------------------------
                                           /benefit amount
  Description (see corresponding  --------------------------------------
         narrative below)              First year       Subsequent years
------------------------------------------------------------------------
(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: E[email protected].

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

[[Page 416]]

[GRAPHIC] [TIFF OMITTED] TP05JA00.000



[[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