Establishing Oil Value for Royalty Due on Indian Leases

DEPARTMENT OF THE INTERIOR

Minerals Management Service

30 CFR Part 206

RIN 1010-AC24

Establishing Oil Value for Royalty Due on Indian Leases

AGENCY: Minerals Management Service, Interior.

ACTION: Supplementary proposed rule.

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SUMMARY: The Minerals Management Service (MMS) is proposing further

changes to its proposed rulemaking regarding the valuation, for royalty

purposes, of crude oil produced from Indian leases. The MMS is

proposing to: Change which index prices would be used for valuation,

change how those index prices would apply, change how transportation

allowances would apply, and streamline proposed Form MMS-4416 for

computing adjustments to value for royalty purposes. These amendments

are intended to simplify and improve the proposed rule.

DATES: Your comments must be submitted on or before March 6, 2000.

ADDRESSES: Address your comments, suggestions, or objections regarding

this supplementary proposed rule to:

By regular U.S. mail. Minerals Management Service, Royalty

Management Program, Rules and Publications Staff, P.O. Box 25165, MS

3021, Denver, Colorado 80225-0165; or

By overnight mail or courier. Minerals Management Service, Royalty

Management Program, Building 85, Room A613, Denver Federal Center,

Denver, Colorado 80225; or

By e-mail. RMP.[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

rnet 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

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

l 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

g 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:

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

ces 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.

Transportation Costs From Lease Versus Reservation Boundary

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.

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:

wording 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

. 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

. 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

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

ral 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

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.. $

(2) Cost--Equipment/Compliance...

(3) Cost--Completing Form MMS-

4416............................

(4) Cost--Filing new 2014 with

Major Portion Uplift............

(5) Benefit--Administrative 1,100,000 1,100,000

Savings.........................

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

Net Costs to Industry...... $ $

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(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.

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.

ce 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.

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:

(1,350 + 675 + 337.5 burden hours) x $50/hour = $118,125

ents 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:

(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

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

roceeds 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.

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

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

($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

se

payors of approximately $1.1 million per year

($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.

irst 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.

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

rections 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

t 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

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

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.

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

tary

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

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.

yalty

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

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

ase 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-

4416...........................

(2) Cost--Calculating Major

Portion........................

(3) Benefit--Administrative 630,500 630,500

Savings........................

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

Net Benefit to Federal $248,500 $520,500

Government...............

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

(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.

d 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

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.

ations 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

ducts 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.

petition, 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

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

osts 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)

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

ration 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:

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

ta 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.

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

e of the number of respondents upward from 125 oil royalty

payors to 225 payors; this is an adjustment of 1,050 hours.

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.

y 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?

ing 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.

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

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:

raph

(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

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).

ransportation 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.

r

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) 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

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)

t

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)

(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.

o.

(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?

* * * *

.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)

tials 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

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.

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.

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;

nd 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.

ay 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.

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Step-by-Step Instructions for MMS Form 4416

t 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.

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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

a 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

ument.

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

ced 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

ng 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.

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.

ontract 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

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

e,

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]

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