Establishing Oil Value for Royalty Due on Federal Leases

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 Federal leases. MMS is proposing

to: eliminate MMS-published differentials; change the way that actual

costs of transportation are calculated; change the definition of

``affiliate'' because of a judicial decision in a case decided after

the close of the most recent comment period; issue binding value

determinations; and add specific regulatory language regarding the

issue of ``second-guessing'' a sale under an arm's-length contract.

These amendments are intended to simplify and improve the proposed

rule.

DATES: Submit comments on or before January 31, 2000.

ADDRESSES: Send your written comments to David S. Guzy, Chief, Rules

and Publications Staff, Royalty Management Program, Minerals Management

Service, P.O. Box 25165, M.S. 3021, Denver, Colorado 80225-0165; or e-

Mail David__G[email protected].

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

Publications Staff, Royalty Management Program, Minerals Management

Service, phone (303) 231-3432, FAX (303) 231-3385, e-Mail

David__G[email protected].

SUPPLEMENTARY INFORMATION: The principal authors of this further

supplementary proposed rule are David A. Hubbard and Deborah Gibbs

Tschudy of the Royalty Management Program (RMP) and Peter Schaumberg

and Geoffrey Heath of the Office of the Solicitor in Washington, D.C.

MMS is specifying a deadline for comments that is less than the 60

days recommended by Executive Order No. 12866. MMS believes that a 30-

day comment period is appropriate in this instance because it

previously extended and reopened the comment periods for several

earlier proposed versions of this rule. MMS also held numerous

workshops across the country to obtain public input on this proposed

rulemaking. MMS also plans to hold public hearings during the 30-day

comment period to give interested parties the opportunity to fully

discuss and comment on this further supplementary proposed rule. MMS

will publish specific dates and locations for the hearings in the

Federal Register.

Most of the provisions in this supplementary proposed rule were in

included in previous proposed rules. All of the comments we received

thus far are part of the rulemaking record and MMS will consider all

such comments before issuing a final rule. Therefore, it is unnecessary

for commenters to resubmit earlier comments on provisions that are not

proposed for further change. MMS requests that comments focus on the

new proposals addressed in this supplementary proposed rule.

I. Background

This further supplementary proposed rule proposes changes to

valuation rules in 30 CFR part 206 that have been in effect since March

1, 1988 (the 1988 rules).

The 1988 rules were developed based on the concept that gross

proceeds received under an arm's-length contract represented the best

measure of the value of production for royalty purposes. Further, those

rules implicitly assumed the existence of a competitive and transparent

market at the lease (or in the field or area) that could be used to

determine the value of production not sold at arm's-length.

Characteristics of competitive markets include: (1) There is a

large number of sellers, no one of whom commands a large share of the

total market, (2) the products of different sellers are functionally

identical and buyers have no preference among sellers, (3) there are so

many buyers that sellers and buyers do not establish personal

relationships with one another, and (4) buyers are perfectly informed

about the prices of different sellers. In the context of particular

leases or fields, generally there is not a large number of sellers.

Further, one or a few of the producers in the lease or field often

control a large share of the production sold. In addition, at the lease

or field level, there are a limited number of buyers and sellers.

Moreover, because of the proprietary nature of individual contract

sales of crude oil, lessees usually will not know the prices at which

other lease interest holders sell their oil. In other words, generally

there is no price transparency at the lease or field level. None of the

comments submitted throughout this nearly four-year rulemaking effort

demonstrated that as a general rule a competitive market exists at the

lease.

The overall lack of a truly competitive market at the lease has

been compounded by the significant changes that occurred in the

domestic industry during the 1980's and early 1990's, which had a

profound effect on how crude oil is marketed today. These changes

included: (1) The major oil companies' creation of separate affiliates

for production, marketing and refining; (2) overall decline in domestic

production and increased dependence on foreign imports and influence of

international trading practices on domestic supply; (3) sharply

increased volatility of oil prices marked by the price collapse in

early 1986 (the last year in which posted prices exceeded spot market

prices), and the rapid rise and decline in prices in late 1990 and

early 1991 in response to the Gulf War; (4) entry and expansion of

resellers, traders, and brokers who bought, transported, and sold

domestic crude oil, taking advantage of pricing and location

discrepancies in much the same way they were doing on the international

market; and (5) development of a futures market for crude oil which

alleviated many of the risks of spot trading. While many of these

factors may be seen as increasing the level of competition, none of

them served to increase the level of price transparency (i.e., the

ability to discern the prices actually paid) at the lease or field or

to simplify application of the existing oil valuation rules.

The 1988 rules placed heavy emphasis on posted prices as a measure

of royalty value, particularly when valuing oil disposed of not at

arm's-length and under no-sales conditions. Posted prices historically

were the primary mechanism for pricing domestic crude oil before the

1980's. However, with the disruption of global petroleum supplies in

the 1970's and decontrol of domestic crude oil prices in 1981, the

domestic petroleum industry began moving away from posted prices and

towards the spot and futures markets to buy and sell crude oil. In

fact, studies commissioned by States and advice from MMS consultants

(Innovation & Information Consultants, Inc.; Micronomics, Inc.; Reed

Consulting Group; and Summit Resource Management, Inc.) found that: (1)

sales prices are often above posted prices and are linked, in some

form, to market prices, such as spot or futures prices, or represent

premia over posted prices; (2) major producers have few truly outright

sales; (3) most major producers use buy/sell exchanges; (4) there are

regional differences in the

[[Page 73821]]

domestic crude oil market, particularly on the West Coast and in the

Rocky Mountain Region, owing to differences in market concentration and

availability of transportation options; and (5) posted prices have

become a progressively less reliable indicator of the market value of

crude oil since the late 1980s.

Development of the futures market and comprehensive publication of

spot prices increased the market transparency of crude oil clearing

prices. As a result, market participants became less willing to accept

long-term sales contracts at fixed prices and instead negotiated short-

term contracts with sales prices linked to spot or futures prices or to

premia over posted prices. Major oil companies, however, generally

continued to pay royalties on their production transferred not at

arm's-length based on posted prices.

Recognizing that posted prices no longer reflected market value,

State and private royalty owners in Alaska, California, Louisiana, New

Mexico, and Texas brought lawsuits against several major oil companies

over improper oil pricing and underpaid royalties. These lawsuits

resulted in several oil companies paying additional royalties and some

adjusting their posted prices to better reflect market value.

The majority of Federal lease oil production in fact is not sold at

arm's length at or near the lease. Most Federal lease oil production is

either moved directly to a refinery without a sale or disposed of under

an exchange agreement (e.g., buy/sell agreements) in which the lessee

exchanges oil at one location for oil at another location. Exchange

agreements frequently do not reference a price, but rather only the

relative difference in the value of crude oils exchanged and thereby

obscure the oil's actual market value. When the agreement does state a

price but is conditioned upon the lessee's purchase of crude oil at a

subsequent exchange point, the price specified in the exchange

agreement does not represent the value of the oil. In a buy-sell

exchange, the parties may state any base price they wish, because their

primary concern is the difference in value between the oil sold and the

oil purchased.

This rulemaking proposes to amend the current regulations by

eliminating posted prices as a measure of value and relying instead on

arm's-length sales prices and spot market prices as market value

indicators. Today, spot prices are readily available to industry

participants via price reporting services, and these and similar prices

play a significant role in crude oil marketing in terms of the basis

upon which deals are negotiated and priced.

Comments received so far during the rulemaking process made it

apparent that regional differences exist in the domestic crude oil

market. These differences are due in large part to geographic isolation

of markets. Accordingly, this further proposed rule would establish

different valuation procedures for three different regions: California

and Alaska, the Rocky Mountain Region, and the rest of the country.

This proposal adopts parts of the February 1998 proposal, but

includes modifications contemplated in the outline published in the

March 12, 1999 notice of reopening of public comment period and notice

of workshops, and a variety of other modifications in response to

public comments.

II. History of This Rulemaking

MMS published an advance notice of its intent to amend the 1988

rules on December 20, 1995 (60 FR 65610). The purpose of that notice

was to solicit comments on new methodologies to establish the royalty

value of Federal (and Indian) crude oil production in view of the

changes in the domestic petroleum market and particularly the market's

move away from posted prices as an indicator of market value. The

comment period on this advance notice closed on March 19, 1996.

Based on comments received on the advance notice, together with

information gained from a number of presentations by experts in the oil

marketing business, MMS published its initial notice of proposed

rulemaking on January 24, 1997 (62 FR 3742). That proposal set out

specific valuation procedures that focused on New York Mercantile

Exchange (NYMEX) prices and Alaska North Slope (ANS) spot prices as

value indicators, depending on the location of the production. It also

clarified the lessee's duty to market the production at no cost to the

Federal Government and required the lessee to use actual transportation

costs instead of Federal Energy Regulatory Commission (FERC) tariffs

for transportation allowances. The comment period for that proposal was

to expire March 25, 1997, but was twice extended--first to April 28,

1997 (62 FR 7189), and then to May 28, 1997 (62 FR 19966). MMS held

public meetings in Lakewood, Colorado, on April 15, 1997, and Houston,

Texas, on April 17, 1997, to hear comments on the proposal.

In response to the variety of comments received on the initial

proposal, MMS published a supplementary proposed rule on July 3, 1997

(62 FR 36030). That proposal expanded the eligibility requirements for

valuing oil disposed of under arm's-length transactions. The comment

period on that proposal closed August 4, 1997.

Because of the substantial comments received on both proposals, MMS

reopened the rulemaking to public comment on September 22, 1997 (62 FR

49460). MMS specifically requested comments on five valuation

alternatives arising from the public comments. The initial comment

period for that request was to close October 22, 1997, but was extended

to November 5, 1997 (62 FR 52518). During the comment period MMS held

seven public workshops to discuss valuation alternatives: in Lakewood,

Colorado, on September 30 and October 1, 1997 (62 FR 50544); Houston,

Texas, on October 7 and 8, 1997, and again on October 14, 1997 (62 FR

50544); Bakersfield, California, on October 16, 1997 (62 FR 52518);

Casper, Wyoming, on October 16, 1997 (62 FR 52518); Roswell, New

Mexico, on October 21, 1997 (62 FR 52518); and Washington, D.C. on

October 27, 1997 (62 FR 52518).

As a result of comments received on the proposed alternatives and

comments made at the public workshops, MMS published a second

supplementary proposed rule on February 6, 1998 (63 FR 6113),

applicable to Federal leases only. The comment period for this second

supplementary proposed rule was to close on March 23, 1998, but was

extended to April 7, 1998 (63 FR 14057). MMS held five public workshops

(63 FR 6887) on the second supplementary proposed rule, as follows:

Houston, Texas, on February 18, 1998; Washington, D.C. on February 25,

1998; Lakewood, Colorado, on March 2, 1998; Bakersfield, California, on

March 11, 1998; and Casper, Wyoming, on March 12, 1998.

Based on a request by Senator Breaux (Louisiana) to hold a meeting

between industry and the Department of the Interior (DOI) to explain

the direction DOI was going in the final rule, MMS once again opened

the public comment period from July 9 through July 24, 1998. Two such

meetings were held, on July 9 and July 22.

On July 16, 1998, as a result of comments during the prior comment

period, MMS published a further supplementary proposed rule that

clarified some of the changes MMS intended to make when the proposed

rule became final.

Also, on July 21, Representatives Miller (California) and Maloney

(New York) sponsored a meeting between DOI, States, the Indian

community, and

[[Page 73822]]

multiple special interest groups. In that meeting DOI received a

variety of comments in support of its efforts to move forward with the

rule and against some of the changes promoted by industry.

The July 22 meeting involved further discussion of industry's

issues and recommendations regarding the proposed rule. MMS immediately

developed written responses to each industry issue and recommendation

based on its published statements in prior proposed rules. MMS also

extended the comment period for the proposed rule until July 31 to

permit comment on the industry recommendations and MMS's responses.

On July 28, 1998, MMS and Departmental officials met with Senate

staff members to further explain the content and rationale of the

proposed rule. The notes from all of these meetings were posted on

MMS's Internet Homepage for interested parties to review during the

comment period.

On August 31, 1998, the Assistant Secretary for Land and Minerals

Management wrote a letter to members of the Senate outlining the

direction the final rule might take on several of the major issues. On

October 8, 1998, the President signed the FY 1999 Department of the

Interior Appropriations Act that contained language extending the

moratorium prohibiting MMS from publishing a final rule until June 1,

1999. On March 4, 1999, the Secretary announced a reopening of the

comment period in response to requests by Members of Congress and

parties interested in moving the process forward to publish a final

rule. The MMS published a Federal Register Notice on March 12, 1999,

reopening the comment period through April 12, 1999, and announced that

it would hold public workshops in Houston, Texas; Albuquerque, New

Mexico; and Washington, D.C. to discuss specific areas of the rule. The

MMS extended the comment period through April 27, 1999, to provide

commenters adequate time to provide comments following the workshops.

The February 6, 1998, proposal, as modified by the July 16, 1998,

further supplementary proposed rule and through consideration of all

comments received during the rulemaking process, led to this further

supplementary proposed rule.

In the discussion below, we use the following conventions: the

January 24, 1997, proposed rule is termed the January 1997 proposal;

the July 3, 1997, supplementary proposed rule is termed the July 1997

proposal; the September 22, 1997, notice reopening the public comment

period is termed the September 1997 notice; the February 6, 1998,

second supplementary proposed rule is termed the February 1998

proposal; the July 16, 1998, further supplementary proposed rule is

termed the July 1998 proposal; and the March 12, 1999, notice of

reopening of public comment period and notice of workshops is termed

the March 1999 notice.

III. Summary and Discussion of Proposed Rule

This proposed rule incorporates changes made in response to

comments on the January 1997 proposal, the July 1997 proposal, the

September 1997 notice, the February 1998 proposal, the July 1998

proposal, and the March 1999 notice. As in the February 1998 proposal,

we also added and renumbered sections and further reorganized the rule

for readability.

Because this proposed rule is a product of changes made in response

to comments received throughout this rulemaking, the preambles of each

of the previous proposals and notices may be consulted in conjunction

with this preamble to trace the evolution of this proposal.

Note that the renumbering and reorganization for this proposal

resulted in the following modifications to the existing rule:

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

Section Modification

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

Secs. 206.100 and 206.101................ Revised.

Sec. 206.102............................. Revised and redesignated as

Secs. 206.102, 206.103,

206.104, 206.105, 206.106,

206.107, and 206.108.

Secs. 206.103 and 206.104................ Redesignated as Secs.

206.119 and 206.109,

respectively.

Sec. 206.105............................. Revised and redesignated as

Secs. 206.110, 206.111,

206.114, 206.115, 206.116,

206.117, and 206.118.

Sec. 206.106............................. Revised and redesignated as

Sec. 206.120.

New Secs. 206.112 and 206.113............ Added.

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

In addition, we rewrote all sections of the existing rule in plain

English so the entire rule would read consistently.

Before proceeding with the summary and discussion of this proposal,

it is necessary to explain further why MMS is not proposing further

changes in certain areas.

Duty to Market. It is a well-established principle that lessees

have the obligation to market lease production for the mutual benefit

of the lessee and lessor, without deduction for the costs of marketing.

See, e.g., Walter Oil and Gas Corp., 111 IBLA 260 (1989); Arco Oil and

Gas Co., 112 IBLA 8 (1989); Taylor Energy Co., 143 IBLA 80 (1998)

(motion for reconsideration pending); Yates Petroleum Corp., 148 IBLA

33 (1999); Amerac Energy Corp., 148 IBLA 82 (1999) (motion for

reconsideration pending); Texaco Exploration and Production Inc., No.

MMS-92-0306-O&G (1999) (concurrence by the Secretary) (action for

judicial review pending, Texaco Exploration and Production Inc. v.

Babbitt, No. 1:99CV01670 (D.D.C.)).

In the context of Federal leases, the D.C. Circuit referred to this

implied lease covenant many years ago in California Co. v. Udall, 296

F.2d 384, 387 (D.C. Cir. 1961), stating that ``the lessee was obligated

to market the product.'' The duty to market at no cost to the lessor is

not unique to Federal leases. See, e.g., Merrill, Covenants Implied in

Oil and Gas Leases (2d Ed. 1940), Secs. 84-86 (Noting ``[n]o part of

the costs of marketing or of preparation for sale is chargeable to the

lessor''); ``Direct Gas Sales: Royalty Problems for the Producer,'' 46

Okla. L. Rev. 235 (1993); Amoco Production Co. v. First Baptist Church

of Pyote, 579 S.W.2d 280 (Tex. Civ. App. 1979), writ ref'd n.r.e., 611

S.W.2d 610 (Tex. 1981), and cases cited in these authorities.

This duty to market means that the lessee must act as a prudent

marketer. The duty to market is an implied covenant of virtually all

oil and gas leases, whether the leases are private, Federal, or State

leases. MMS as lessor has never shared in the ``risks'' of marketing

and has never allowed deductions from royalty value for marketing

costs. This proposed rulemaking makes no change to the lessee's duty to

market.

The decisions cited above establish several principles. First, the

lessee has an implied duty to prudently market the production for the

mutual benefit of both the lessee and the lessor. The creation and

development of markets is the essence of that obligation. As the IBLA

correctly expressed it ten years ago in Arco Oil and Gas Co., supra:

The creation and development of markets for production is the

very essence of the lessee's implied obligation to prudently market

production from the lease at the highest price obtainable for the

mutual benefit of the lessee and lessor. Traditionally,

[[Page 73823]]

Federal gas lessees have borne 100 percent of the costs of

developing a market for gas. Appellant has cited no authority, nor

do we find any, which supports an allowance for creation and

development of markets for the royalty share of production.

112 IBLA at 11.

Because of industry's repeatedly-expressed concerns in the comments

and workshops, MMS emphasizes that this does not imply that lessees are

somehow prohibited from marketing at the lease and must market

production ``downstream.'' Lessees may market at the lease without

breaching the duty to market. However, if a lessee chooses to market

downstream, the choice to do so is for the mutual benefit of itself and

the lessor, and does not affect the lessee's relationship to the

lessor. The choice to market downstream does not make marketing costs

deductible or permit the lessee to disregard part of the sales price

obtained at a downstream market.

In addition, lessees have always borne all of the marketing costs.

The Department has not knowingly permitted an allowance or deduction

from royalty value for marketing costs. As the Board held a decade ago

in Walter Oil and Gas Corp., supra:

The only allowances recognized as proper deductions in

determining royalty value are transportation allowances for the cost

of transporting production from the leasehold to the first available

market, which has been considered a relevant factor pursuant to 30

CFR. Sec. 206.150(e) * * * and processing allowances for processed

gas authorized by 30 C.F.R. Sec. 206.152(a)(2) (1987) * * *.

Walter's unsupported assumption that it is somehow entitled to

deduct its marketing costs from royalty value fails in the face of

contrary regulatory requirements * * *.

111 IBLA at 265.

Lessees may deduct from value only those costs allowed by the

regulations. The only deductible costs are transportation costs,

processing costs (for ``wet'' gas with heavier entrained liquid

hydrocarbons), and, for leases which so provide, an operating allowance

under Sec. 206.120.

Further, marketing costs are not deductible, regardless of whether

the lessee bears them directly or transfers the marketing function or

costs to a contractor or an affiliate.

Moreover, the fact that marketing arrangements enhance the lessee's

ability to obtain a higher price does not imply that marketing costs

are deductible. It also follows that a lessee may not deduct or

disregard for royalty purposes the additional benefits it gains or

value it receives through obtaining a higher price through its

marketing skill or expertise. If the lessee manages to obtain a higher

price for its oil through skillful marketing efforts, that higher

price, less transportation costs, is the minimum royalty value under

the gross proceeds rule.

At the same time, the location of the market at which the lessee

chooses to sell its production does not change the lessee's obligation.

Much of industry's opposition to the duty-to-market provision during

this rulemaking process revolves around the argument that when royalty

value is based on the sale of production at a downstream location, the

downstream transportation, risks, and related services add more value

to the oil than is reflected in allowances MMS permits.

The industry commenters' argument is contrary to established

principles and uniform longstanding practice. Valuation based upon a

``downstream'' sale or disposition of production has been commonplace

for many years. For sales at distant markets, the lessee is entitled to

an allowance for transportation costs, but not for marketing costs.

Sales away from (or ``downstream'' from) the lease often are the

starting point for determining royalty value, and the costs of

transportation always have been allowed in order to ascertain value at

or near the lease. A lessee who transports production to sell it at a

market remote from the lease or field is entitled to an allowance for

the costs of transportation. See 30 C.F.R. 206.104, 206.105 (crude

oil), 206.156 and 206.157 (gas) (1988-present). Before the 1988

regulations, transportation costs were allowed under judicial and

administrative cases. See, e.g., United States v. General Petroleum

Corp., 73 F. Supp 225 (S.D. Cal. 1946), aff'd, Continental Oil Co. v.

United States, 184 F.2d 802 (9th Cir. 1950); Arco Oil and Gas Co., 109

IBLA 34 (1989); Shell Oil Co., 52 IBLA 15 (1981); Shell Oil Co., 70

I.D. 393, 396 (1963).

An excellent example is Marathon Oil Co. v. United States, 604 F.

Supp. 1375 (D. Alaska 1985), aff'd, 807 F.2d 759 (9th Cir. 1986), cert.

denied, 480 U.S. 940 (1987). In that case, Marathon produced natural

gas from Federal leases in Alaska, and sold it in Japan after overseas

transportation in liquid form by tanker. The court held that MMS

properly deducted Marathon's costs of transportation (including

liquefaction) from the sales price in Japan to derive the royalty value

(gross proceeds) at the lease.

Indeed, transportation allowances have been common for decades

precisely because the initial basis for establishing value often is a

``downstream'' sales price. Industry's argument that MMS is somehow

improperly trying to ``tap into'' the benefits industry derives from

its marketing expertise clouds the real issue. If a lessee can obtain a

better price by selling away from the lease, then it will do so. How

the lessee markets its production is its decision. The lessor is

entitled to its royalty share of the total value derived from the

production regardless of how the lessee chooses to dispose of it. The

United States as lessor always has shared in the ``benefit'' of

``downstream'' marketing away from the lease, and has allowed

deductions for the cost of transportation accordingly.

Moreover, these principles do not change in the event that a

wholly-owned or wholly-commonly-owned affiliated marketing entity buys

other production at arm's length from other working interest holders in

the field at the same price it pays to its affiliated producer. The

industry wants to limit royalty value to supposedly ``comparable''

sales at the lease even when the lessee receives a higher price for its

production. In effect, industry wants to force MMS to adopt a ``lowest

common denominator'' theory of valuation--i.e., the price at which any

production is sold at arm's length at the lease will be the value of

production initially transferred non-arm's-length, even if the latter

production nets a higher price in the open market. That position is

incorrect for several reasons.

First, it would enable a lessee whose enterprise realizes more

proceeds or greater value for its production than some other producers

in the field to avoid paying royalty on part of those proceeds. If the

lessee sells downstream, its gross proceeds are the higher price

realized on the sale downstream, minus the lessee's transportation

costs, regardless of the fact that other producers sold for less. The

industry's position is directly contrary to Marathon Oil Co. v. United

States, supra. If the lessee first transfers to a wholly-owned or

wholly-commonly-owned affiliate who then resells at arm's length

downstream, it is still true that the producing entity could have sold

its production at the point and at the price its affiliate did, instead

of using the wholly-owned affiliate arrangement. It is perfectly proper

to value the production of a producer who markets through a wholly-

owned affiliate at a higher level than the production that other

producers sell at arm's length in the first instance, when the gas (or

oil) marketed through the wholly-owned affiliate commands a higher

price. Indeed, this is the very situation which the Third Circuit

correctly anticipated in Shell Oil Co. v. Babbitt, 125 F.3d 172 (3d

Cir. 1997).

[[Page 73824]]

Further, the industry's position would create an incentive for a

lessee to sell some small percentage of its production at the lease at

arm's length for a lower price so that it can pay royalty on the rest

of its production at that price. Such a result is contrary to the

intent and meaning of the gross proceeds rule.

MMS agrees that the duty to market production for the mutual

benefit of the lessee and the lessor at no cost to the lessor is not

the same as the lessee's duty to put production into marketable

condition at no cost to the lessor. However, the fact that the two

duties are not identical does not support the industry commenters'

position. The decision of the Secretary and the Assistant Secretary for

Land and Minerals Management in Texaco Exploration and Production Inc.,

supra (at pp. 16-19), discusses the relationship of the two duties and

MMS affirms their rationale.

Industry comparable sales model. In this proposal, MMS did not

adopt the industry-proposed comparable sales model to value production

not sold at arm's length. We continue to believe that there are

meaningful spot prices applicable to production in all areas other than

the Rocky Mountains. With the exception of the Rocky Mountain Region,

spot and spot-related prices drive the manner in which crude oil is

bought and traded in the U.S. Spot prices play a major role in crude

oil marketing and are readily available to lessees through price

reporting services.

We believe spot prices are the best indicator of the value of

production and are preferable to attempting to use supposedly

comparable arm's-length sales in the field or area. Commenters have not

demonstrated the consistent existence or availability of such

transactions for volumes sufficient to use for royalty valuation.

Contrary to the industry commenters, MMS believes that nationwide about

two-thirds of crude oil production is disposed of non-arm's length. As

previously mentioned, the general lack of competitive and transparent

markets at the lease makes the attempt to find comparable sales

transactions far inferior to the use of index prices.

In addition, the various industry proposals have substantial

practical difficulties since companies are not privy to other

companies' ``comparable'' sales transactions. Even if a comparable

sales model included only a lessee's own arm's-length sales or

purchases, such information is unaudited for current periods. Further,

it is difficult to determine what portion of lease production must be

sold at arm's length to reliably determine the value of the remainder

of the production. This supplementary proposed rule thus primarily uses

index prices, adjusted for location and quality, to establish value for

oil not sold at arm's length.

California, and the West Coast in general, has long been recognized

as a separate crude oil market isolated from the rest of the country.

ANS crude is competitive with California crudes. While it may be true

that only 10 percent of ANS crude is sold on the spot market, over 30

percent of the oil refined in California is ANS oil. An interagency

study has found that companies engaged in buying and selling California

crude oil commonly use ANS spot prices as the benchmark for determining

California crude values (Final Interagency Report on the Valuation of

Oil Produced from Federal Leases in California, May 16, 1996; Long

Beach litigation). These companies apparently have no difficulty in

adjusting the ANS prices for quality differences to derive the prices,

including premia over postings, they are willing to pay for California

crude oils. MMS believes ANS spot prices are a recognized benchmark for

valuing California crudes and a reliable indicator of the market value

of California crude oils.

Comments alleging that ANS spot prices are unreliable because ANS

crude is thinly traded were analyzed for MMS by Innovation &

Information Consultants, Inc. (Memorandum to MMS file, September 25,

1997). They report that it is the spot market for local California

crude oils, not ANS crude, that is thinly traded and thus leads to

unreliable price indices. They also report that there is a high degree

of correlation between ANS spot prices and prices actually paid for

California crudes. They indicate that the major oil companies in

California regularly make comparisons between California crude oils and

ANS with the understanding and expectation that a California crude

should equate to ANS in value after accounting for location and quality

differences.

The Rocky Mountain benchmarks for production not sold at arm's

length are hierarchical and would not allow lessees to choose the

benchmark most favorable to them. Rather, a lessee would have to use

the first benchmark that applies to its situation--that is, first

tendering, then a weighted average of sales and purchases, then

Cushing, Oklahoma, adjusted spot prices, and lastly an MMS-established

value. MMS proposes adopting a particular tendering alternative

(designed with what MMS intends as safeguards against manipulation) as

a first benchmark for the Rocky Mountain Region for production not sold

at arm's length because of the lack of a reliable spot price in that

region. One of the Rocky Mountain State commenters recommended this

method as the initial benchmark in that region. MMS has acquiesced in

that recommendation but nevertheless has substantial concerns about the

potential for manipulation of tendering programs. MMS would closely

monitor the reliability and workability of this benchmark. MMS's

response to the comments regarding minimum volume and bid requirements

is provided in Section IV below.

IV. Section-by-Section Analysis

Before discussing the individual sections of this proposed rule, it

is appropriate to review the basic premises of this proposal. When

crude oil is produced, it is either sold at arm's length or is refined

without ever being sold at arm's length. If crude oil is exchanged for

other crude oil at arm's length, the oil received in the exchange is

either sold at arm's length or is refined without ever being sold at

arm's length. Under this proposal, oil that ultimately is sold at arm's

length before refining generally will be valued based on the gross

proceeds accruing to the seller under the arm's-length sale. This

includes oil that is exchanged at arm's length where the oil received

in exchange is ultimately sold at arm's length. (The exceptions reflect

particular circumstances in which MMS believes the arm's-length sale

does not or may not reliably reflect the real value.) However, this

proposal also provides the option for the lessee to apply index prices

or benchmark values because of the difficulty of ``tracing'' production

in some exchanges and affiliate resales. If oil (or oil received in

exchange) is refined without being sold at arm's length, then the value

would be based on appropriate index prices or other methods, as

explained below.

These principles would apply regardless of whether oil is sold or

transferred to one or more affiliates or other persons in non-arm's-

length transactions before the arm's-length sale, and regardless of the

number of those non-arm's-length transactions. They also would apply if

an arm's-length exchange occurs before an arm's-length sale. (However,

MMS believes that if there are multiple exchanges before an arm's-

length sale, using the ultimate arm's-length sales price may in some

cases require too much ``tracing'' of the oil to be cost-efficient for

lessee and lessor alike. Consequently, under such circumstances, MMS

would provide the option to determine value

[[Page 73825]]

based either on the arm's-length gross proceeds or on an index or

benchmark basis. The same option would be provided for valuing

production that is first sold or transferred to an affiliate and then

resold at arm's length.)

Section 206.100 What is the purpose of this subpart?

Proposed section 206.100 includes the content of the existing

section except for minor wording changes to improve clarity. At

Sec. 206.100(a), we have added some further language clarifying the

respective roles of lessees and designees. (Those terms are defined in

Sec. 206.101, and those definitions follow the definitions contained in

Section 3 of the Federal Oil and Gas Royalty Management Act, 30 U.S.C.

1702, as amended by Section 2 of the Federal Oil and Gas Royalty

Simplification and Fairness Act, Public Law 104-185, 110 Stat. 1700.)

Specifically, if you are a designee and you or your affiliate

dispose of production on behalf of a lessee, references to ``you'' and

``your'' in the rule would refer to you or your affiliate. In this

event, you would have to report and pay royalty by applying the rule to

your and your affiliate's disposition of the lessee's oil. If you are a

designee and you report and pay royalties for a lessee but do not

dispose of the lessee's production, the references to ``you'' and

``your'' would refer to the lessee. In that case, you as a designee

would have to determine royalty value and report and pay royalty by

applying the rule to the lessee's disposition of its oil. Some examples

will illustrate the principle.

Assume that the designee is the unit operator, and that the

operator sells all of the production of the respective working interest

owners on their behalf and is the designee for each of them. For each

of those working interest owners, the operator, as designee, would

report and pay royalties on the basis of the operator's disposition of

the production. For example, if the operator transferred the oil to its

affiliate, who then resold the oil at arm's length, the royalty value

would be the gross proceeds accruing to the designee's affiliate in the

arm's-length resale under Sec. 206.102, or the appropriate index or

benchmark value under Sec. 206.103, as explained further below.

Alternatively, assume the operator is the designee but a lessee

disposes of its own production. Assume the lessee transfers its oil to

an affiliate, who then resells the oil at arm's length. In this case,

the operator would have to obtain the information from the lessee, and

report and pay royalties on the basis of the gross proceeds accruing to

the lessee's affiliate in the arm's-length resale under Sec. 206.102,

or, at the lessee's option, on the basis of the appropriate index or

benchmark value under Sec. 206.103.

In some cases, the designee is the purchaser of the oil. Assume the

operator disposes of the lessee's oil and that the operator is not

affiliated with the designee-purchaser. Because the lessee's sale to

the designee is an arm's-length transaction, then under Sec. 206.102

the designee would report and pay royalty on the total consideration

(the gross proceeds) it paid to the lessee.

The content of proposed Sec. 206.100(b) and (c) is the same as in

the corresponding existing paragraphs, but we rewrote them for clarity.

Paragraph (b) says that this subpart would not apply if these

regulations are inconsistent with a Federal statute, a settlement

agreement between the United States and a lessee resulting from

administrative or judicial litigation, or an express provision of an

oil and gas lease subject to this subpart. If so, the statute,

settlement agreement, or lease provision would govern to the extent of

the inconsistency.

Proposed paragraph (c) says MMS may audit and adjust all royalty

payments. We removed existing paragraph (d). It said the regulations in

this subpart are intended to ensure that the United States discharges

its trust responsibilities concerning Indian oil and gas leases. Since

Indian leases are subject to a separate set of valuation regulations at

30 CFR 206.50 that include the same language as existing paragraph (d),

we believe the existing language at paragraph 206.100(d) is not needed.

Section 206.101 Definitions.

The definitions section remains largely the same as in the January

1997 proposal. However, MMS proposes several additions and

clarifications consistent with changes to the rule throughout the

rulemaking process and in response to comments received.

The July 1997 proposal (62 FR 36030) added a definition of non-

competitive crude oil call as well as a new definition of competitive

crude oil call. This supplementary proposed rule does not use either of

these terms. Therefore, they have been deleted from the proposed

definitions section.

However, oil subject to a noncompetitive crude oil call would be

examined in view of paragraphs 206.102(c)(1) and (c)(2) to determine

whether the prices received represent market value. The value of oil

involved in a noncompetitive crude oil call thus ultimately would be

the lessee's total consideration or the value determined by the non-

arm's-length methods in Sec. 206.103.

We propose to modify the definition of arm's-length contract to

remove the criteria for determining affiliation. Instead, these

criteria would be included in the new definition of affiliate discussed

below.

We also propose to modify the definition of exchange agreement to

delete the statement that exchange agreements do not include agreements

whose principal purpose is transportation. MMS believes that

transportation exchanges, while having different purposes than other

types of exchanges, properly should be included under the generic

definition of exchange agreements. We also propose to add, for clarity,

several examples of other types of exchange agreements. These would

include, but not be limited to, exchanges of produced oil for specific

types of crude oil (e.g., West Texas Intermediate); exchanges of

produced oil for other crude oil at other locations (Location Trades);

exchanges of produced oil for futures contracts (Exchanges for

Physical, or EFP); exchanges of produced oil for similar oil produced

in different months (Time Trades); exchanges of produced oil for other

grades of oil (Grade Trades); and multi-party exchanges (for example,

party A exchanges with party B, who then exchanges with party C, who

then exchanges with party A).

We also propose to modify the definition of gross proceeds to

clarify that they include payments made to reduce or buy down the

purchase price of oil to be produced later. The concept that such

payments are part of gross proceeds was included in the January 1997

proposal at paragraph 206.102(a)(5). Moving this provision directly to

the gross proceeds definition would further clarify the components of

gross proceeds and improve the structure of the rule.

We also clarified that gross proceeds would include payments for

marketing, along with payments for such services as dehydration,

measurement, and gathering. All of these are services that the lessee

must perform at no cost to the Federal Government.

Also, since this proposal bases valuation for some production on

crude oil spot prices for other than ANS oil, we propose to change the

definitions of index pricing and MMS-approved publication to include

other spot prices. Index pricing would mean using ANS crude oil spot

prices, WTI crude oil spot prices at Cushing, Oklahoma, or other

appropriate crude oil spot prices for royalty valuation. MMS-approved

[[Page 73826]]

publication would mean a publication MMS approves for determining ANS

spot prices, other spot prices, or location differentials.

We also would delete the definitions of aggregation point, prompt

month and NYMEX because they are not used in this proposal. All three

of these terms were used in earlier versions of the proposed rule in

applying various non-arm's-length benchmarks. But this proposal would

apply spot, rather than NYMEX prices, and eliminate proposed Form MMS-

4415, so none of these definitions would be needed.

We also would add three new definitions of terms used in the

February 1998 proposal and incorporated in this proposal. They are

affiliate, Rocky Mountain Region, and tendering program.

``Affiliate would mean a person who controls, is controlled by, or

is under common control with another person. For purposes of this

subpart:

(1) Ownership or common ownership of more than 50 percent of the

voting securities, or instruments of ownership, or other forms of

ownership, of another person would constitute control. Ownership of

less than 10 percent creates a presumption of noncontrol which MMS may

rebut.

(2) If there is ownership or common ownership of between 10 and 50

percent of the voting securities, or instruments of ownership, or other

forms of ownership, of another person, MMS would consider the following

factors in determining whether there is control under the circumstances

of a particular case:

(i) the extent to which there are common officers or directors;

(ii) with respect to the voting securities, or instruments of

ownership, or other forms of ownership,

(A) the percentage of ownership or common ownership;

(B) the relative percentage of ownership or common ownership

compared to the percentage(s) of ownership by other persons;

(C) whether a person is the greatest single owner; and

(D) whether there is an opposing voting bloc of greater ownership;

(iii) operation of a lease, plant, or other facility;

(iv) the extent of participation by other owners in operations and

day-to-day management of a lease, plant, or other facility; and

(v) other evidence of power to exercise control over or common

control with another person.

(3) Regardless of any percentage of ownership or common ownership,

relatives, either by blood or marriage, would be affiliates.''

The July 1998 proposal (63 FR 38356) retained the criteria for

determining affiliation that are contained in the existing rule. The

March 1999 notice that included the letter to the Senate (64 FR 12268)

also indicated that MMS likely would retain the same criteria that are

in the existing rule.

In response to the March 1999 notice, industry commenters proposed

a set of criteria which lessees could use to rebut the presumption of

control that arises from ownership or common ownership of between 10

and 50 percent. While MMS does not agree with the industry proposal, a

judicial decision in a case decided after the close of the most recent

comment period affects the criteria for determining control and the

associated presumption in the existing rule.

In National Mining Association v. Department of the Interior, 177

F.3d 1 (D.C. Cir. 1999) (decided May 28, 1999), the United States Court

of Appeals for the District of Columbia Circuit addressed the Office of

Surface Mining Reclamation and Enforcement's (OSM's) so-called

``ownership and control'' rule at 30 CFR 773.5(b). That rule presumed

ownership or control under six identified circumstances. One of those

circumstances was where one entity owned between 10 and 50 percent of

another entity. The court found that OSM had not offered any basis to

support the rule's presumption ``that an owner of as little as ten per

cent of a company's stock controls it.'' 177 F.3d at 6-7. The court

continued, ``While ten percent ownership may, under specific

circumstances, confer control, OSM has cited no authority for the

proposition that it is ordinarily likely to do so.'' Id. (Emphasis

added.) In a footnote, the court referred to the existing MMS rule:

In its brief OSM referred the court to several regulations

promulgated by other agencies but none of them presumes control

based simply on a ten percent ownership stake, although another

Department of Interior regulation does so. See 30 CFR 206.101(b)

[sic] (``based on the instruments of ownership of the voting

securities of an entity, or based on other forms of ownership: * * *

(b) Ownership of 10 through 50 percent creates a presumption of

control''). We do not consider the validity of section 206.101 here.

The United States did not file a petition for rehearing. Nor did

the United States seek Supreme Court review.

In this proposal, MMS is revising the definition of ``affiliate''

in light of the National Mining Association decision. In the event of

ownership or common ownership of between 10 and 50 percent, the second

paragraph of the definition in this proposal, instead of creating a

presumption of control, identifies a number of factors that MMS would

consider in determining whether there is control under the

circumstances of a particular case.

With respect to ownership or common ownership, the new definition

would identify such factors as the percentage of ownership, the

relative percentage of ownership as compared with other owners, whether

a person is the greatest single owner, and whether there is an opposing

voting bloc of greater ownership. All of these are relevant factors in

determining whether there is control in a particular case.

For example, company A could own one third of the voting stock of

company B, while no other owner owns any percentage close to that. A is

the greatest single owner, and it is very likely that A has control of

B. If, in addition, A manages the day-to-day operations of B and the

other owners effectively are passive investors, it would be very clear

that A controls B and that they are affiliates.

A different example would be if A owns 20 percent of B, at the same

time that C and D each own 35 percent of B. In such a case, it would be

much harder to demonstrate that A controls B, and doing so would depend

on additional facts that would show that A has effective control.

Yet another example would be if A owns 12 percent of B and other

owners own roughly equivalent percentages of B. A may or may not

control B, again depending on what additional circumstances are

present.

We emphasize that simply because one entity is found not to control

another on the basis of stock ownership and other factors, and

therefore that the entities are not affiliates, that does not always

mean that the relationship between the two entities is at arm's length.

The entities may be engaged in a cooperative venture and therefore not

have opposing economic interests. (An example is the situation in Xeno,

Inc., 134 IBLA 172 (1995), in which a number of lessees in a large

field combined to form another entity to purchase their gas, then

gather, compress, and treat it, and then resell it to another

purchaser.)

The proposed definition also identifies other factors in addition

to ownership interests that are relevant to determining control. These

include the extent of common officers or directors, operation by one

entity of a lease or a

[[Page 73827]]

facility, the extent of participation by different owners in operations

and day-to-day management of an entity, and other evidence of power to

exercise control or common control. These factors would be evaluated on

a case-by-case basis.

The proposed definition would continue the existing provisions that

ownership of more than 50 percent constitutes control, and that

relatives, either by blood or marriage, are affiliates regardless of

any percentage of ownership or common ownership. Likewise, the proposed

definition would continue the exiting provision that ownership of less

than 10 percent would presume noncontrol that MMS may rebut. The

National Mining Association decision does not affect these provisions.

Arm's-length contract would mean a contract or agreement between

independent persons who are not affiliates and who have opposing

economic interests regarding that contract. To be considered arm's

length for any production month, a contract would have to satisfy this

definition for that month, as well as when the contract was executed.

Again, we have defined affiliate separately for clarity.

In our February 1998 proposal, we asked for comments on the Rocky

Mountain Area definition. We wanted to know whether other States or

regions should be included in this definition and, conversely, whether

the definition included States or regions that should be deleted. For

example, although some participants in MMS's workshops believed the

entire State of New Mexico belongs outside the Rocky Mountain Region

for this rule's purposes, others believed that oil marketing in the

northwest portion of New Mexico is similar to that in the other Rocky

Mountain States. Some of these participants suggested that northwest

New Mexico (not including the Permian Basin) more appropriately should

be included in the Rocky Mountain Region.

Several commenters said the term's wording could conflict with the

generic use of the term ``area'' elsewhere in the rule. As a result, we

changed ``Rocky Mountain Area'' to ``Rocky Mountain Region'' in this

supplementary proposed rule.

We received several comments, pro and con, regarding inclusion of

part or all of New Mexico in the Rocky Mountain Region definition. The

most telling comment was from the State of New Mexico itself,

indicating that production there has much closer ties to Midland,

Texas, than any Rocky Mountain markets. Thus, MMS has excluded New

Mexico from the definition in this proposal. Other comments about

additions and deletions of specific States or regions were limited, and

MMS does not believe they warrant further changes to the definition.

Rocky Mountain Region would mean the States of Colorado, Montana, North

Dakota, South Dakota, Utah, and Wyoming.

For the Rocky Mountain Region, this proposal incorporates tendering

as one of the non-arm's-length valuation benchmarks; hence we propose a

new definition. Tendering program would mean a company offer of a

portion of its crude oil produced from a field or area for competitive

bidding, regardless of whether the production is offered or sold at or

near the lease or unit or away from the lease or unit. The definition

in the February 1998 proposal said ``* * * from a field, area, or other

geographical/physical unit for competitive bidding.'' Several

commenters said ``or other geographical/physical unit'' was confusing,

and one commenter suggested deleting it. Although our intent was to

provide for circumstances where tendered oil is produced from a very

specific and more finite source than a field or area, we agree that the

terminology as originally written could be confusing. Thus we have

deleted ``or other geographical/physical unit'' in this proposal. The

revised definition should cover all circumstances, since any production

tendered will be from a given field or area. The offer and sale of oil

under a tendering program would not be limited to offers or sales at or

near the lease or unit. Oil could be tendered for bid or sale at remote

or ``downstream'' locations. The proposal includes clarifying language

to remove any potential ambiguity on this point.

Several commenters said the definition of ``sale'' should be

modified to describe how transfers of production from a working

interest owner to the operator under a joint operating agreement should

be treated for valuation purposes. Two specific circumstances were

described, namely where the operator sells the working interest owner's

share of production: (1) At arm's length, or (2) to the operator's

affiliate. The commenters said that if the initial transfer from the

working interest owner to the operator, or the sale of the working

interest owner's production by the operator, were not considered an

arm's-length sale, there may be an inappropriate result. For example,

the working interest owner might be required to either ``trace'' value

back from the operator's affiliate's resale, or apply Sec. 206.103. We

are not persuaded that the result under this proposed rule would be

inappropriate, and believe that the proposed definition of ``sale'' is

clear and succinct.

Section 206.102 How Do I Calculate Royalty Value for Oil That I or my

Affiliate Sell(s) Under an Arm's-length Contract?

We propose to revise and reorganize Sec. 206.102 as written in the

several previous proposed rules. We would revise Sec. 206.102 to

specifically address valuation of oil ultimately sold under arm's-

length contracts. That sale may occur immediately, or may follow one or

more non-arm's-length transfers or sales of the oil or one or more

arm's-length exchanges.

Proposed paragraph (a) states that value is the gross proceeds

accruing to you or your affiliate under an arm's-length contract, less

applicable allowances. Similarly, if you sell or transfer your Federal

oil production to some other person at less than arm's length (except

for a non-arm's-length exchange), and that person or its affiliate then

sells the oil at arm's length, royalty value would be the other

person's (or its affiliate's) gross proceeds under the arm's-length

contract. If you transfer under a non-arm's-length exchange, you must

use Sec. 206.103.

For example, a lessee might sell its Federal oil production to a

person who is not an ``affiliate'' as defined, but with whom its

relationship is not one of ``opposing economic interests'' and

therefore is not at arm's length. An illustrative example would be a

number of working interest owners in a large field forming a

cooperative venture that purchases all of the working interest owners'

production and resells the combined volumes to a purchaser at arm's

length. Xeno, Inc., 134 IBLA 172 (1995), involved a similar situation

for a gas field. If no one of the working interest owners owned 10

percent or more of the new entity, the new entity would not be an

``affiliate'' of any of them. Nevertheless, the relationship between

the new entity and the respective working interest owners would not be

at arm's length. In this instance, it would be appropriate to value the

production based on the arm's-length sale price the cooperative venture

received for the oil.

Paragraph 206.102(a)(3) of the February 1998 proposal was meant to

be specific to those cases, such as Xeno, where the transfer is not

between affiliates but the sale is not arm's length because the parties

do not have opposing economic interests. However, several commenters

could not see the difference between (a)(3) and (a)(2); the latter

applied only to sales or transfers to an affiliate who then sells the

oil at

[[Page 73828]]

arm's length. Because the result of both paragraphs would be the same,

and to stem this confusion, we propose to eliminate previous paragraph

(a)(3) and include its intent in revised paragraph (a)(2). That

paragraph would now say value is the gross proceeds accruing to the

seller under the arm's-length contract, less applicable allowances,

where you sell or transfer to your affiliate or another person under a

non-arm's-length contract and that affiliate or person or another

affiliate of either of them then sells the oil under an arm's-length

contract. As a result of this change, paragraph (a)(4) of the February

1998 proposal would now become paragraph (a)(3).

In all these circumstances, you would have to value the production

based on the gross proceeds accruing to you, your affiliate, or other

person to whom you transferred the oil (or its affiliate) when the oil

ultimately was sold at arm's length unless you elect to use index

pricing or benchmarks under Sec. 206.102(d).

Paragraph (a)(5) of the January 1997 proposal dealt with inclusion

in gross proceeds of payments made to reduce or buy down the price of

oil to be produced in later periods. We removed this paragraph in the

February 1998 proposal but added the concept within the definition of

gross proceeds as discussed above. This supplementary proposed rule

reflects the February 1998 proposal in this regard without change.

Proposed paragraph (b) would clarify how to value the oil produced

from your lease when you sell or transfer it to your affiliate or to

another person under a non-arm's-length contract, and your affiliate,

the other person, or an affiliate of either of them sells the oil at

arm's-length under multiple arm's-length contracts. In this case, value

would be the volume-weighted average of the values established under

paragraph (a) for each contract for the sale of oil produced from that

lease.

A number of commenters said that calculating this volume-weighted

average value would be extremely problematic because it often would be

difficult to tie specific contracts to specific Federal oil production,

especially where commingling of various production is involved. MMS

acknowledges that proper royalty calculations can be complicated in

such situations, but that does not diminish the lessee's duty to pay

proper royalties on its Federal production. Even under the existing

rules, circumstances similar to those described by the commenters often

require that the lessee allocate values and volumes. We believe this

provision is consistent with ongoing practice.

Proposed paragraph (c) would specify two exceptions to the use of

arm's-length gross proceeds. It would also require you to apply the

exceptions to each of your contracts separately. Proposed paragraphs

(c)(1) and (c)(2) would remain largely unchanged from paragraphs (a)(2)

and (a)(3) in the January 1997 proposal and from Sec. 206.102(b)(1) (i)

and (ii) of the existing rules, except for additional language included

in (c)(2) regarding ``second guessing,'' as discussed below.

Paragraph (a)(4)(ii) of the July 1997 proposal said that where an

arm's-length contract price does not represent market value because an

overall balance between volumes bought and sold is maintained between

the buyer and seller, royalty value would be calculated as if the sale

were not at arm's length.

In the February 1998 proposal, MMS decided to remove that language

as a specific, separate provision. Rather, in considering whether an

arm's-length contract reflects your or your affiliates' total

consideration or market value (proposed paragraphs (c)(1) and (c)(2)),

MMS would examine whether the buyer and seller maintain an overall

balance between volumes they bought from and sold to each other. Under

these paragraphs, if an overall balance agreement were found to exist,

MMS would require you to value your production under Sec. 206.103 or

the total consideration received.

Several commenters said that removal of the overall balance

provision and relying on MMS to find such agreements put an undue

burden on MMS. They further stated that MMS would have great difficulty

verifying the existence of such agreements. We continue to believe,

however, that verification of overall balancing arrangements, and

appropriate follow up, is best left to audit in conjunction with the

provisions of paragraphs 206.102 (c)(1) and (c)(2). Thus, this proposal

does not contain any specific language regarding overall balancing

agreements.

Likewise, this proposal does not contain any specific language

regarding noncompetitive crude oil calls. In response to the July 1997

and February 1998 proposals, and in MMS's public workshops, several

commenters asserted that producers often negotiate competitive prices

even if a non-competitive call provision exists and a call on

production is exercised. We agree and we propose not to treat oil sold

under a noncompetitive crude oil call differently than other arm's-

length sales. However, because the sale occurred in the context of a

noncompetitive crude oil call, MMS would examine the transaction more

carefully in view of paragraphs 206.102 (c)(1) and (c)(2) to determine

whether the prices received represent market value.

This supplementary proposed rule contains language in paragraph

206.102(c)(2)(ii) regarding MMS's intent not to ``second guess''

industry marketing decisions. The rule would state that MMS will not

use this provision to simply substitute its judgment of the market

value of the oil for the proceeds received by the seller under an

arm's-length sales contract. The fact that the price received by the

seller in an arm's-length transaction is less than other measures of

market price, such as index prices or other arm's-length sales, is

insufficient to establish breach of the duty to market unless MMS finds

additional evidence that the seller acted unreasonably or in bad faith

in the sale of oil from the lease.

In response to industry concerns, in its July 1998 proposal, MMS

proposed adding specific language to Sec. 206.102(c)(2)(ii) that MMS

would not use the ``breach of duty'' provision to second-guess industry

marketing decisions unless the arm's-length prices were substantially

below market value. However, in their comments on the July 1998

proposal, industry and their representative organizations stated that

the terms ``substantially below'' and ``market value'' were not easily

defined and could lead to MMS questioning legitimate transactions. One

commenter said that in the past, MMS has rejected legitimate, at-the-

lease prices in favor of higher, downstream prices. One commenter

believed that as long as a company is acting in good faith, they have

nothing to fear with MMS ``second-guessing'' their decisions. One

commenter offered alternate ``breach of duty to market'' language.

At the March 1999 workshops, industry commenters expressed concern

that if a company sold production at the lease under an arm's-length

arrangement, MMS might later ``second-guess'' the transaction and

determine that the royalty should have been paid on a higher price than

the company actually received, such as index. They proposed specific

language to be added to the rule and preamble.

One State commenter also proposed specific regulatory language

regarding ``second-guessing.'' A public interest group commented that

it would support language that MMS will not second-guess arm's-length

contract prices received, provided that lessees disclose balancing

arrangements between

[[Page 73829]]

themselves and the unaffiliated companies.

The provision MMS was attempting to clarify with its proposed

additional language is identical to the provision in the existing rules

(see 30 CFR 206.102(b)(1)(iii)). It has been in those rules for over a

decade and has not been used to second-guess a lessee's marketing

decisions to try to impose the benchmarks at Sec. 206.102(c) on arm's-

length transactions. It is longstanding MMS policy to rely on arm's-

length prices as the best measure of value, and we have no intention of

changing this. We expect no expansion of the use of this provision in

the future as a result of this proposed rewrite.

We propose including the term ``unreasonably'' because we think

that limiting the proposed provision only to situations involving ``bad

faith'' is too narrow. We do not believe that a royalty interest holder

should bear the consequences of a lessee's decision to enter into a

transaction that no reasonable businessman would agree to. We

anticipate that such situations would be extraordinarily rare. However,

we believe that the duty to market for the mutual benefit of the lessee

and the lessor may be breached by unreasonable actions that do not

involve knowing or deliberate bad faith. The July 1998 proposal

included language that MMS would not use the provision to dispute

lessees' marketing decisions made ``reasonably and in good faith.''

Although some industry commenters initially stated that the term ``good

faith'' was too subjective, industry commenters later recommended

including this term in their proposed rewrite of this section. Thus, we

do not think that the terms ``unreasonable'' or ``bad faith'' are too

subjective.

Requiring a lessee to include in gross proceeds or royalty value,

amounts that were improperly deducted for marketing costs, costs of

putting production in marketable condition, or other costs that are the

responsibility of the lessee, does not constitute ``second-guessing''

an arm's-length contract.

Proposed paragraph 206.102(d)(1) provides the option, where arm's-

length sales follow one or more arm's-length exchanges, to apply either

the arm's-length gross proceeds or the index or benchmark value

appropriate to the region of production.

In the February 1998 proposal, MMS expanded gross proceeds

valuation to include situations where the oil received in exchange is

ultimately sold at arm's length, regardless of the number of exchanges

involved. However, many industry comments claimed that tracing multiple

exchanges would be overly burdensome. MMS understands the potential

administrative burden of tracing. However, we also are well aware of

the desire of other producers, as expressed in the meetings sponsored

by Senator Breaux and other Senators on July 9 and July 22, 1998, to be

able to use prices received in arm's-length sales following multiple

exchanges. As a result, under this proposal, MMS would allow lessees

the option of using either their arm's-length gross proceeds regardless

of the number of arm's-length exchanges preceding the arm's-length

sale, or the provisions of Sec. 206.103 (index prices or, in the Rocky

Mountain Region, benchmarks). This process would preserve the integrity

of the rule's underlying principle of applying arm's-length gross

proceeds where appropriate, but still allow use of index/benchmark

values that fairly represent market value where ``tracing'' would be

too burdensome.

The chosen option would apply for at least 2 years. The lessee

would have to use this method to value all of its crude oil that the

lessee or its affiliate sells at arm's length following one or more

exchanges.

The option to choose between index valuation and gross proceeds is

not available for oil that is not sold at arm's length after the

exchange or for oil subject to non-arm's-length exchanges regardless of

whether an arm's-length sale follows such an exchange. The provisions

of Sec. 206.103 would apply to such dispositions. We included these

qualifications to assure that lessees would not abuse the system by

choosing case-specific options or time periods for the purpose of

reducing royalty, or by using non-arm's-length exchange differentials

to determine royalty value. We acknowledge that exchanges between

affiliates are not at arm's length. Because there is potential for

inflated differentials in such exchanges, production so transferred,

even if followed by an arm's-length sale, would have to be valued at

the appropriate index/benchmark value under this proposal.

Proposed paragraph (d)(2) of this proposal is new and results from

comments received throughout the rulemaking process. Some commenters

believe that where lessees sell or transfer production to an affiliate

and the affiliate resells the oil at arm's length, they should be able

to apply an alternative valuation method other than tracing the

production to its final disposition. In this proposal, similar to the

option for sales following arm's-length exchange agreements, we provide

the option to use either the ultimate arm's-length gross proceeds or

the appropriate index or benchmark value. Also, proposed paragraph

(d)(2)(ii) states that whichever option you select, you must apply that

same option for all of your production disposed of through affiliate

resales at arm's length, and that you not change this election more

often than once every 2 years. Again, we believe this achieves the best

balance of valuing production based on arm's-length gross proceeds and

limiting administrative burdens.

Proposed paragraph (e) would be essentially the same as paragraphs

(b)(2) and (3) of Sec. 206.102 in the January 1997 proposal and

paragraphs (d)(2) and (3) of the February 1998 proposal and comes

directly from existing Sec. 206.102(b)(2) and (j). We would eliminate

proposed paragraph (b)(1) of the January 1997 proposal (paragraph

(d)(1) of the February 1998 proposal) in connection with the change to

the definition of ``affiliate'' explained previously in this preamble.

Proposed section 206.102(e)(2) addresses circumstances in which a

purchaser does not pay the full price obtainable by the seller under

the contract between them. The proposed section, which is similar to

the current section 206.102(j), establishes that if the seller takes

reasonable efforts to obtain the highest price to which it is entitled

under the contract, then the price it obtains will be the basis for

determining value.

Industry commenters suggested rewriting the section now proposed at

206.102(e)(2) to make it virtually identical to the language in section

206.102(j) of the current rule. In other words, industry suggests using

the term ``lessee'' instead of ``seller.'' This proposal generally

requires arm's-length gross proceeds as royalty value regardless of

whether the ultimate seller is the lessee, an affiliate, or another

person to whom the lessee has sold or transferred production under a

non-arm's-length contract. All of these persons would come within the

term ``seller.'' MMS therefore would retain this term instead of using

the term ``lessee.''

Section 206.103 How Do I Value Oil That Is Not Sold Under an Arm's-

Length Contract?

In the February 1998 proposal, this section replaced paragraph

206.102(c) of the January 1997 proposal. This proposal includes a few

changes in this section as explained below. This section would deal

specifically with valuation of oil you could not value under

Sec. 206.102 because the oil is not ultimately sold at arm's length or

is otherwise excepted under Sec. 206.102. It

[[Page 73830]]

may also apply where you have elected one of the options available at

Sec. 206.102(d)(1) or (2).

Also, paragraph 206.102(c)(1) of the January 1997 proposal would

have permitted you an option if you first transferred your oil

production to an affiliate and that affiliate or another affiliate

disposed of the oil under an arm's-length contract. The option was to

value your oil at either the gross proceeds accruing to your affiliate

under its arm's-length contract or the appropriate index price. For the

reasons discussed earlier, we have reinserted that option in this

proposal under paragraph 206.102(d)(2). MMS believes that where arm's-

length transactions satisfying the provisions of Sec. 206.102 occur,

royalty value generally should be the arm's-length gross proceeds.

However, providing this option should afford some administrative relief

to lessees while assuring receipt of fair royalty values.

We received various comments about use of ANS spot prices. Most

industry commenters said that because there are significant differences

between ANS and California crudes in terms of quality, product yield,

transportation modes and distances, and timing of production versus

delivery, the ANS spot price is not a good value indicator for

California crude oil production. The State of California and City of

Long Beach, on the other hand, continue to endorse the use of ANS spot

prices. They indicate that ANS spot prices are used in many arm's-

length transactions and that ANS crude constitutes a large percentage

of California refinery feedstock. MMS's own experience, including

participation in the interagency task force investigating California

oil undervaluation, shows that ANS crude frequently has been used by

industry as a valuation benchmark for valuing California crudes. Also,

because of the control of the pipeline transportation network in

California by a few companies who also act as purchasers of a large

portion of California crude oil production, the use of posted prices or

contracts based on postings as a basis for valuing crude disposed of at

other than arm's-length is questionable. We continue to believe that,

with proper adjustments for location and quality differences, the ANS

spot price is the best available measure of royalty value for Federal

oil production in California that is not sold at arm's length.

Paragraph 206.103(b) would apply to production from leases in the

Rocky Mountain Region, a defined term. As discussed above, production

in the Rocky Mountain Region is controlled by relatively few companies,

and the number of buyers is more limited than in the Texas, Gulf Coast,

or Midcontinent areas. As a result, there is less spot market activity

and trading in this area due to the control over production and

refining. The majority of written comments we received, as well as oral

comments in our public meetings, agreed that a separate valuation

procedure is needed for the Rocky Mountain Region. For these reasons,

we propose the following valuation hierarchy for the Rocky Mountain

Region:

(1) As in the February 1998 proposal, if you have an MMS-approved

tendering program (a defined term), the value of production from leases

in the area the tendering program covers would be the highest price bid

for tendered volumes. Under your tendering program you would have to

offer and sell at least 30 percent of your production from both Federal

and non-Federal leases in that area. You also would have to receive at

least three bids for the tendered volumes from bidders who do not have

their own tendering programs that cover some or all of the same area.

MMS added the several qualifications stated above to ensure receipt

of market value under tendering programs. First, as provided in the

February 1998 proposal, royalty value would be the highest price bid

rather than some other individual or average value. Several commenters

said this is inappropriate because it is possible that a single bidder

may only bid on some small portion of the tendered volumes at a high

price, but this price would then apply to all tendered volumes. We

continue to believe, however, that to assure receipt of market value,

value must be based on the highest bid received.

Second, you would have to offer and sell at least 30 percent of

your production from both Federal and non-Federal leases in that area.

The rationale for this minimum percentage is to ensure that the lessee

puts a sufficient volume of its own production share up for bid to

minimize the possibility that it could abuse the system for Federal

royalty or State tax payment purposes. MMS originally chose 33\1/3\

percent as the minimum because it exceeded the typical combined Federal

royalty rate and effective composite State tax and royalty rates for

onshore oil leases by roughly 10 percent. We received various comments

that this figure was too high and that it was not appropriate to

consider State royalties, since they would not be payable on Federal

leases. MMS recognizes this fact but also notes that for the oil-

producing states in the Rocky Mountain Region the combined Federal

royalty rate and state composite effective tax rate on Federal oil

production typically ranges from about 17 to 27 percent. These

percentages do not include state royalty rates. In this proposal, we

thus chose 30 percent, or just above the high end of the royalty and

tax range, as the minimum percentage the lessee would have to tender

for sale to assure that some of the lessee's equity share of production

generally was involved. Likewise, the tendering program would be

required to include non-Federal lease production volumes in the 30

percent determination to ensure that the program isn't aimed at

limiting Federal royalty value.

Third, as in the February 1998 proposal, to ensure receipt of

competitive bids, your tendering program would have to result in at

least three bids from bidders who do not have their own tendering

programs covering some or all of the same area. In response to the

February 1998 proposal, we received several comments that requiring

three bidders was too stringent and that in many cases there simply

would not be that many qualified bidders. We have reviewed this

criterion and continue to believe that a minimum number of bidders is

essential to ensure receipt of market value. We believe that at least

three bidders are needed to provide an adequate measure of market value

and have retained this provision in this proposal. Further, MMS is

concerned about the possibility of cross-bidding between companies at

below-market prices, which could otherwise satisfy the minimum number

of bidders requirement. That is why we have retained the stipulation

that bids would have to come from bidders who do not also have their

own tendering programs in the area.

(2) As in the February 1998 proposal, for the second method in the

valuation hierarchy for the Rocky Mountain Region, value would be the

volume-weighted average gross proceeds accruing to the seller under

your and your affiliates' arm's-length contracts for the purchase or

sale of production from the field or area during the production month.

The total volume purchased or sold under those contracts would have to

exceed 50 percent of your and your affiliates' production from both

Federal and non-Federal leases in the same field or area during that

month.

Under the February 1998 proposal, MMS proposed this method as the

next alternative if a qualified tendering program did not exist. It is

an effort to establish value based on actual transactions by the lessee

and its

[[Page 73831]]

affiliate(s). We received a number of comments during the rulemaking

process that MMS should look not only to sales by the lessee, but also

purchases a lessee and its affiliates make in the field or area. Just

as for the tendering program, MMS believes a floor percentage of the

lessee's and its affiliates' production should be set to prevent any

abuse. Although we received several comments that the 50 percent

minimum figure is too high, it is not intended to be a more stringent

standard than the 30 percent floor associated with the tendering

program. That is because the 50 percent floor would apply to the

lessee's and its affiliates' sales and purchases in the field or area,

rather than just sales as in the tendering program. For example,

Company A produces 10,000 barrels of crude oil in a given field during

the production month. Company A sells 1,000 barrels under an arm's-

length contract. Company A also has a refining affiliate, Company B,

that purchases the remaining 9,000 barrels of Company A's production

and 5,000 barrels of oil under arm's-length purchase contracts with

other producers in the same field. Together the arm's-length sales by

Company A and the arm's-length purchases by its affiliate, Company B,

are 6,000 barrels, or 60 percent of the lessee's production in the

field that month. The volume-weighted arm's-length gross proceeds

accruing to Company A and paid by Company B for these 6,000 barrels

would represent royalty value for the 9,000 barrels of Company A's

Federal lease production in the field that could not be valued under

Sec. 206.102.

This proposal would continue to require using the unadjusted

volume-weighted average gross proceeds accruing to the seller in all of

the lessee's and its affiliates' arm's-length sales or purchases, not

just those that may be considered comparable by quality or volume. We

received several comments that this would result in improper valuation

of some oil that was significantly different in quality than that

associated with the ``average'' oil. However, we believe that

production in the same field or area generally would be similar in

quality. Further, given that these sales and purchases would have to be

greater than 50 percent of all of the lessee's production in the field

or area, we believe that it is not necessary to distinguish comparable-

volume contracts.

MMS received several industry comments that the proposed rule would

cause hardships for producers who have marketing, but not refining,

affiliates. The marketing affiliate takes the producing affiliate's

production and also buys production from various other sources before

reselling or otherwise disposing of the combined volumes. Section

206.102 of the February 1998 proposal would have required the producer

to base royalty value on its marketing affiliate's various arm's-length

sales and allocate the proper values back to the Federal lease

production. Many commenters said this ``tracing'' would be difficult at

best, but others wanted the opportunity to do so. One commenter

suggested that as an alternative the lessee should be permitted to base

the value of its production on the prices its marketing affiliate pays

for crude oil it buys at arm's length in the same field or area.

We cannot agree with this proposal because an overriding general

premise of this rulemaking is that where oil ultimately is sold at

arm's length before refining, it should be valued based on the gross

proceeds accruing to the seller under the arm's-length sale (with the

option to use index or benchmark values under some circumstances as

discussed earlier). This means the marketing affiliate's arm's-length

resale should form the basis for valuing the producing affiliate's

production. To do otherwise would be inconsistent with the way arm's-

length resales are treated elsewhere in this proposal.

(3) As in the February 1998 proposal, if you could not apply either

of the first two valuation criteria for the Rocky Mountain Region,

value would be the average of the daily mean spot prices published in

any MMS-approved publication for WTI crude at Cushing, Oklahoma, for

deliveries during the production month.

This paragraph is very similar to paragraph 206.102(c)(2)(i) of the

January 1997 proposal. The main difference is that rather than using

NYMEX futures prices, we apply Cushing spot prices in this proposal, as

in the February 1998 proposal. This was due to an industry comment that

since Cushing spot and NYMEX futures prices track closely over time and

that we propose to use spot prices in the other two valuation regions,

using the spot price in the Rocky Mountain Region would lend

consistency with no downside effects. MMS proposes to make this the

third method, to be used only if the first two do not apply, because of

distances between Rocky Mountain Region locations and Cushing,

Oklahoma, and the additional difficulties in deriving location/quality

differentials.

(4) If you should demonstrate to MMS's satisfaction that paragraphs

(b)(1) through (b)(3) would result in an unreasonable value for your

production as a result of circumstances regarding that production, the

MMS Director may establish an alternative valuation method.

This method is the last alternative and would be intended for use

only in very limited and highly unusual circumstances. We believe there

should be very few such alternative valuation methods, and each one

should be subject to careful review.

We received several comments that this option should be offered

nationwide. However, we believe this is inappropriate because valid

spot prices for which reasonable location and quality adjustments may

be made are available throughout the rest of the country. While the

Cushing spot price likewise is valid, the remoteness of the Rocky

Mountain Region may in some cases cause such severe difficulties in

making reasonable location/quality adjustments that an alternative

method may be warranted.

Paragraph 206.103(c) would apply to production from leases not

located in California, Alaska, or the Rocky Mountain Region. MMS

proposes that value be the average of the daily mean spot prices

published in an MMS-approved publication:

(1) For the market center nearest your lease for crude oil similar

in quality to that of your production. For example, at the St. James,

Louisiana, market center, spot prices are published for both Light

Louisiana Sweet and Eugene Island crude oils. Their quality

specifications differ significantly, and you would have to use the spot

price for the oil that is similar to your production; and

(2) For deliveries during the production month.

You would calculate the daily mean spot price by averaging the

daily high and low prices for the month in the selected publication.

You would use only the days and corresponding spot prices for which

such prices are published. You would be required to adjust the value

for applicable location and quality differentials, and you could adjust

it for transportation costs, under Sec. 206.112 of this subpart.

There may be cases where the nearest market center may not be the

appropriate one for you to use because the quality of your production

better matches that typically traded at another, more distant market

center. In such cases, you could use this more distant market center to

value your production.

MMS proposes changing the valuation procedure 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

[[Page 73832]]

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. Although industry continued

to object to any form of valuation that begins with values away from

the lease, we received several comments that using the spot price

rather than NYMEX futures prices would improve administration of the

rule with no apparent adverse effects.

MMS is not proposing any of the alternatives here (or for

California and Alaska) that it did for the Rocky Mountain Region where

oil cannot be valued under proposed Sec. 206.102. That is because,

unlike the Rocky Mountain Region, there are meaningful published spot

prices applicable to production in the other regions (e.g., Cushing,

Oklahoma; St. James, Louisiana; Empire, Louisiana; Midland, Texas; Los

Angeles/San Francisco, California). In the United States, with the

exception of the Rocky Mountain Region, spot and related index-type

prices drive the manner in which crude oil is bought and traded. Spot

prices play a significant role in crude oil marketing. They form a

basis on which deals are negotiated and priced and are readily

available to lessees via price reporting services. We believe spot

prices are the best indicator of value for production from leases

outside the Rocky Mountain Region. Therefore, it is not necessary to

consider other, less accurate means of valuing production not sold at

arm's length for regions outside the Rocky Mountains.

We received numerous comments about MMS inappropriately moving the

value of production away from the lease without permitting deduction of

marketing costs or the value added by the lessee and its affiliates.

This proposal would not allow the costs of marketing production as a

deduction from index prices or prices based on gross proceeds. The

requirement to market production for the mutual benefit of the lessee

and the lessor at no cost to the lessor is an implied covenant of the

lease, and is not unique to Federal leases. See Section III for more

detail. With respect to the costs of putting production into marketable

condition, see, e.g., Mesa Operating Limited Partnership v. Department

of the Interior, 931 F.2d 318 (5th Cir. 1991), cert. denied, 502 U.S.

1058 (1992); Texaco, Inc. v. Quarterman, Civil No. 96-CV-08-J (D. Wyo.

1997). It follows that any payments the lessee receives for performing

such services are part of the value of the production and are royalty

bearing. MMS is not altering this principle in this proposal. This

proposal, in Sec. 206.106 discussed below, simply would make express

the longstanding implied covenant to market.

Proposed paragraph 206.103(d) is paragraph 206.102(c)(3) of the

January 1997 proposal with minor clarifying word changes. It states

that if MMS determines that any of the index (spot) prices are no

longer available or no longer represent reasonable royalty value, then

MMS would exercise the Secretary's authority to establish value based

on other relevant matters. These could include, for example, well-

established market basket formulas.

Proposed paragraph 206.103(e) addresses situations where you

transport your oil directly to your or your affiliate's refinery and

believe that use of a particular index price is unreasonable. In that

event, you could apply to the MMS Director for approval to use a value

representing the market at the refinery. Based on the lack of comments

on this provision, which was included in the February 1998 proposal, we

included it in this proposal with only minor clarifying changes.

Section 206.104 What Index Price Publications Are Acceptable to MMS?

Section 206.104 of this proposal is paragraphs (c)(4), (c)(5), and

(c)(6) of Sec. 206.102 from the January 1997 proposal with an added

reference to spot prices for crude oil other than ANS. The few comments

that MMS received on this section simply said that industry should have

some input into which publications are accepted by MMS. We have

included this section in this proposal unchanged. MMS would consult

with industry groups as appropriate in deciding which publications

should be used for index pricing.

Section 206.105 What Records Must I Keep To Support My Calculations of

Value Under This Subpart?

Proposed section 206.105 specifies that you must be able to show

how you calculated the value you reported, including all adjustments.

This is important because if you were unable to demonstrate on audit

how you calculated the value you reported to MMS, you could be

subjected to sanctions for false reporting.

Section 206.106 What Are My Responsibilities To Place Production Into

Marketable Condition and To Market Production?

Proposed section 206.106 is paragraph 206.102(e)(1) of the January

1997 proposal with minor clarifying word changes. It is unchanged from

section 206.106 of in the February 1998 proposal. It says you must

place oil in marketable condition and market the oil for the mutual

benefit of the lessee and the lessor at no cost to the Federal

Government. We received many comments from industry that MMS is

inappropriately trying to force industry to bear all marketing costs

and that MMS should share in these costs. Comments from States

supported the ``duty to market'' concept. We discussed this issue

previously. MMS is not altering the lessee's obligation to market

production at no cost to the lessor in this proposal.

The January 1997 proposal also included, at paragraph

206.102(e)(2), a provision regarding the lessee's general

responsibility to pay interest if the lessee reports value improperly

and underpays royalties, or to take a credit for overpaid royalties. We

deleted this provision in this proposal because these matters are

already covered in other parts of MMS's regulations.

Section 206.107 How Do I Request a Value Determination?

This section of the February 1998 proposal provided that lessees

may ask MMS for valuation guidance or propose a valuation method to

MMS. It stated that MMS will promptly review the proposal and provide

the requestor with a nonbinding determination.

During the workshops help in March and April 1999 and in their

written comments, industry representatives proposed a provision under

which MMS would provide binding valuation determinations on a case-by-

case basis. Among other provisions, the determination would have no

precedential value beyond the facts in the case. Under the industry

proposal, the MMS would have 180 days from the date the lessee

submitted the request to make a decision, otherwise the request would

be deemed approved. An MMS decision on a request would be subject to

the existing appeals process.

Industry commenters cited the need for obtaining timely valuation

determinations that can be relied on for satisfying royalty

obligations. Industry commenters referred MMS to procedures used by

other Federal agencies to provide advance guidance on how to comply

with their regulations.

State commenters expressed general opposition to or concerns with

binding determinations, stating that information could be inaccurate,

incomplete, or dated and that MMS should have discretion over issuing

any binding

[[Page 73833]]

determinations. A public interest group indicated it would support a

binding determination as long as all of the information submitted is

correct and verifiable and that the determination only applies to the

requestor. A congressional commenter stated that this issue remains of

concern and needs to be developed further.

We disagree with the industry comment to make issuing a

determination mandatory. In the vast majority of cases, the lessee will

receive a value determination either from the Assistant Secretary, Land

and Minerals Management, or from MMS staff. However, there are some

situations in which a value determination is not appropriate. In

proposed section 206.107(b)(3), we identify some situations in which

MMS typically will not issue a value determination. These include: (1)

Requests based on hypothetical situations; (2) matters that are

inherently factual in nature; and (3) matters that are the subject of

pending litigation or administrative appeals.

We also disagree with the industry comment that there should be a

time limit for MMS responses to requests for value determinations. None

of the other Federal agency processes identified by the industry

commenters includes a time limitation.

We agree with the industry proposal to allow for lessees to propose

a valuation method. We also agree that lessees should be able to rely

on valuation methods they propose unless and until MMS modifies or

rejects the proposal. However, industry commenters proposed that the

lessee's proposed method would be automatically adopted if MMS failed

to timely issue a determination.

We disagree with this comment. First, we did not find a similar

approach in any of the other Federal agency procedures identified by

the industry commenters. Second, such a system would be open to abuse.

A lessee could propose an unreasonable valuation method and rely upon

it until MMS had time to evaluate it and reject it. Further, if MMS

were unable to respond within the stated time frame, it would be unable

to correct an improper valuation method and the consequent

undervaluation of oil.

The industry commenters proposed that lessees could appeal

determinations with which they disagreed. A State representative

commented that only bills (i.e., orders to pay) should be appealable.

We agree with the State commenter. Under the proposed rule, value

determinations issued by the Assistant Secretary would be the final

action of the Department and subject to judicial review under the

Administrative Procedure Act, 5 U.S.C. 701-706. Additionally, we

propose in section 206.107(d)(2) that value determinations by MMS staff

would not be subject to administrative appeal. A lessee that disagrees

with a value determination by MMS staff may either request

reconsideration or choose not to follow the determination, since it

would not be binding on the lessee. However, if a lessee, either

simultaneously or later, receives an order to pay on the same legal

basis as the MMS staff value determination, the lessee may appeal the

order under 30 CFR part 290 subpart B. Lessees should not be able to

invoke the administrative appeal process until they receive actual

orders to pay.

Industry commenters suggested that the Department should only

change a value determination prospectively. A public interest group

recommended that MMS should be able to audit the value determination

requests, and if MMS finds the information provided by the lessee to be

incomplete or incorrect, could change the determination and penalize

the lessee.

We agree that as a general matter, value determinations may be

changed only prospectively. The proposed rule expressly states that a

value determination issued by the Assistant Secretary ``is binding on

both you and MMS until the Assistant Secretary modifies or rescinds

it.''

The proposed rule also provides that a value determination by MMS

staff is binding on MMS and delegated States with respect to the

specific situation addressed in the determination unless the MMS

Director or the Assistant Secretary modifies or rescinds it. This

contrasts with value determinations signed by the Assistant Secretary,

because MMS staff value determinations are not binding on the lessee.

This means that MMS will not issue an order inconsistent with a value

determination by MMS staff, but if a lessee does not follow that value

determination, it may receive an order requiring it to pay royalties on

the same basis as the value determination.

Under proposed paragraph (e), a change in applicable statutes or

regulations on which a value determination is based would supersede the

value determination, regardless of whether the MMS Director or the

Assistant Secretary modifies or rescinds the value determination. This

would apply to all value determinations, including those signed by the

Assistant Secretary, and would apply to all periods to which the change

in statute or regulation applies.

Under proposed paragraph (f), the MMS Director or the Assistant

Secretary generally would not modify or rescind a value determination

retroactively (regardless of whether the Assistant Secretary or MMS

staff issued it), unless (1) there was a misstatement or omission of

material facts; or (2) the facts subsequently developed are materially

different from the facts on which the guidance was based. This reflects

the principle that a value determination should not stand if it was

obtained through fraud or knowing submission of false information, or

if the underlying factual premises on which a value determination is

based are not correct. Lessees cannot bind the government through

fraudulent means or through determinations that are not based on the

actual facts. If it were not possible to retroactively modify or

withdraw a value determination in such situations, the government and

the public would be open to serious abuse. (MMS generally would not

audit the facts presented in a value determination request at the time

of the request, but instead would audit these facts as appropriate when

auditing payments made under the determination.)

Proposed section 206.107(g) provides that MMS may make requests and

replies available to the public subject to the confidentiality

requirements of proposed section 206.108.

Section 206.108 Does MMS Protect Information I Provide?

As noted in the February 1998 proposal, Section 206.108 is

paragraph 206.102(h) of the January 1997 proposal, but with minor

wording changes for clarity.

Section 206.109 When May I Take a Transportation Allowance in

Determining Value?

Proposed Section 206.109 includes the substance of Sec. 206.104 of

the January 1997 proposal with only minor wording changes. However, in

this proposal, we removed the last two sentences of paragraph (a)

regarding transportation of oil that MMS takes as royalty in kind.

These provisions were unnecessary because this issue is addressed in

the royalty-in-kind regulations in Sec. 208.8.

This section also includes the provision that you may not take a

transportation allowance greater than 50 percent of the value of the

oil determined under this subpart. We received several comments that

MMS should relax this limitation. However, paragraph 206.109(c)(2)

would continue the existing practice that you may ask MMS to approve a

larger transportation allowance by demonstrating that your

[[Page 73834]]

reasonable, actual, and necessary costs exceed the 50 percent

limitation.

Sections 206.110 and 206.111 How Do I Determine a Transportation

Allowance Under an Arm's-Length Transportation Contract, and How Do I

Determine a Transportation Allowance Under a Non-Arm's-Length

Transportation Contract?

Proposed sections 206.110 and 206.111 are paragraphs 206.105(a) and

(b), respectively, of the existing rule, rewritten to reflect plain

English.

Based on several comments received during the most recent

workshops, we are proposing two changes to the calculation of actual

transportation costs under Sec. 206.111(g). First, under the current

regulations, a change in ownership does not alter the depreciation

schedule. That is, a transportation system cannot be depreciated more

than once by one or more owners. Proposed paragraph Sec. 206.111(g)(2)

would state that an arm's-length change in ownership of a

transportation system would result in a new depreciation schedule for

purposes of the allowance calculation. If you or your affiliate

purchase an existing transportation system at arm's length, your

initial capital investment is equal to your purchase price of the

transportation system.

Second, proposed paragraph Sec. 206.111(g)(3) would provide that

even after a transportation system has been, depreciated below a value

equal to ten percent of your original capital investment, you may

continue to include in the allowance calculation a cost equal to ten

percent of your initial capital investment in the transportation system

multiplied by a rate of return under paragraph (h) of this section.

Under the current regulations a lessee is not allowed to claim any

depreciation or return on capital once a pipeline is fully depreciated.

We are proposing under paragraph Sec. 206.111(g)(3) to allow lessees to

continue to claim a return on a portion of their capital investment

regardless of the pipeline's depreciation status.

Paragraph Sec. 206.111(g)(4) (existing paragraph

Sec. 206.105(b)(2)(B) of the current regulations), provides an

alternative for transportation facilities first placed in service after

March 1, 1988. We are not proposing any change to this paragraph, but

we specifically request comments on whether this paragraph should be

retained in the final rule. We are asking whether this paragraph is

necessary in light of the changes we are proposing to the calculation

of actual transportation costs and because it is our understanding that

this paragraph has been used in few, if any, situations.

The existing rule uses the Standard and Poor's Industrial BBB bond

rate as an allowable rate of return on capital investment for producers

who transport oil through their own pipelines (see 30 CFR

206.157(b)(2)(v)). Two commenters from affiliated companies said the

use of the BBB bond rate as an allowable return within the calculation

of actual costs of transportation is arbitrary and would be considered

unacceptable by any court. They said the actual rate should be much

higher, reflecting the real rates of return seen in the Gulf of Mexico,

and particularly in deep waters to recognize additional risk. They

assert that the current rate of return based on one times BBB is too

low to accurately reflect a company's cost of capital. At the public

workshops held in March and April 1999 and in their written comments,

industry commenters stated that the current rate does not adequately

account for the cost of equity or the inherent risks of transportation

systems. Industry commenters suggested that the rate should be two

times the Standard and Poor's BBB bond rate.

While MMS is not proposing specific changes to the rate of return

used in calculating the return on investment under Sec. 206.111(h), we

specifically request comments on whether we should modify the rate of

return and, if so, what that rate should be. MMS specifically requests

comment on modifying the rate of return based on multiples of the

Standard and Poor's BBB bond rate, such as 1.5 times or 2 times the BBB

bond rate.

A member of Congress commented that the rate of return should be

based on a company's weighted average cost of capital, taking into

account both a company's return on debt and return on equity similar to

the method used in formal rate making for electric utilities. We

request comments on using either a company-specific or industry-wide

weighted cost of capital to determine the rate of return. Your comments

should address the administrative burden of verifying an individual

company's or industry-wide annual weighted average cost of capital.

We also request comments on any other method of determining the

appropriate rate of return applicable to transportation systems for oil

production from Federal lands. Consistent with MMS's goals in this

rulemaking, any proposed methods should provide certainty and

simplicity while assuring that the public receives market value for its

royalty interest in Federal lease oil production.

In the most recent round of comments, industry commenters proposed

that transportation allowances in non-arm's-length situations should be

based principally on the value of the service. That is, the allowance

should be based on what companies pay under arm's-length contracts.

Under industry's proposal, where more than 20 percent of the pipeline

volume is transported at arm's length, an annualized volume-weighted

average of the arm's-length rates would be used. Where less than 20

percent of the volume is arm's-length, the current MMS actual-cost

method would apply; however, the rate of return would increase from the

current level to twice the Standard and Poor's BBB bond rate.

Undepreciated capital investment would never be less than 10 percent of

the original capital cost.

Industry commenters asserted that they only agreed to the MMS

actual-cost method under the 1988 rules because of the provision to use

FERC tariffs. They oppose MMS proposing to revoke use of tariffs

without allowing an adequate transportation allowance rate to be

deducted from the value of production at the market centers.

Comments supporting industry's position that FERC tariffs still

should be permitted in lieu of actual costs include: (1) FERC's

decisions regarding its jurisdiction were flawed; (2) it was unfair for

pipeline owners' transportation allowances to be based on their actual

costs while non-owners could use the tariff; (3) the producing

affiliate does not have the records needed to calculate actual costs;

(4) audit costs for industry and MMS would increase; and (5) FERC's

interpretation on jurisdiction applied only to offshore pipelines.

State commenters agreed with MMS's position under the latest

proposed rule. One congressional commenter stated that MMS should

confer with FERC and develop a proposal that is more consistent with

accepted public rate setting practices.

MMS did not adopt the industry value-of-service proposal in this

proposal because we continue to believe that the cost of service is

most appropriate in determining deductions for royalty purposes. This

is consistent with longstanding valuation and allowance principles.

However, in response to industry comments and as noted above, we

propose to modify the way depreciation is claimed when a transportation

facility is sold. We also propose to permit a rate of return against a

minimum of ten percent of the original capital investment even after

the remaining depreciable amount falls below that level. We also are

asking for

[[Page 73835]]

comments on the appropriate rate of return to be used in transportation

allowance calculations. We believe these proposed changes and requests

for comments respond in a fair and balanced way to the comments

received.

This supplementary proposed rule continues MMS's position that FERC

tariffs should not be permitted as a substitute for actual costs in

non-arm's-length situations. We continue to believe that FERC tariffs

often exceed the transporter's actual costs. Further, we cannot presume

FERC's reasoning to be flawed where it has determined that it does not

have jurisdiction over offshore pipelines.

MMS continues to maintain that it is fair to allow a lessee with an

arm's-length transportation contract to use the amount it pays to the

pipeline while limiting a producer transporting over its own pipeline

to its actual costs. In both cases the amount allowed represents the

actual costs incurred to transport the oil.

MMS also maintains that where producing and transporting affiliates

are involved, the entity claiming the allowance should be able to

acquire any needed records from its affiliate. It may be true that

audit costs could be somewhat higher without the FERC tariff option.

However, we believe that the principle of permitting only actual costs,

including a reasonable rate of return, is consistent with longstanding

royalty valuation and allowance principles and fairly and reasonably

protects the public interest.

We also note that even if FERC's non-jurisdictional determinations

are exclusive to offshore pipelines, those pipelines involve the great

majority of transportation allowance deductions for Federal royalty

purposes.

Section 206.112 What Adjustments and Transportation Allowances Apply

When I Value Oil Using Index Pricing?

Proposed section 206.112 describes how to adjust the index price

for location differentials, quality differentials, and transportation

allowances depending on how you dispose of your oil.

In the February 1998 proposal, Sec. 206.112 contained a ``menu'' of

possible adjustments that could apply in different circumstances, and

Sec. 206.113 prescribed which of the adjustments from the ``menu''

applied to specific circumstances. In this proposal, we have eliminated

the ``menu'' and instead combined proposed Secs. 206.112 and 206.113

into one section that describes what adjustments apply when using index

pricing. The ``menu'' of options would no longer be necessary with the

elimination of aggregation points and MMS-published differentials, as

discussed below. This new paragraph would cover all situations

regardless of lease location, so there would be no need for

geographical breakdown of adjustments and allowances.

This proposal eliminates the previously-proposed location

differential between the index pricing point and the market center.

This is because under the valuation procedures proposed under the

February 1998 proposal and continued in this proposal, the index

pricing point and market center are synonymous.

Under section 206.112(b)(1) of the February 1998 proposal, MMS

would have specified location/quality differentials between aggregation

points and market centers. Section 206.118 of the February 1998

proposal would have required lessees to submit a Form MMS-4415, from

which MMS would have calculated these differentials. In this further

supplementary proposed rule, in response to the various comments

received throughout the rulemaking, we have eliminated MMS-published

differentials. MMS believes that lessees using index pricing generally

would have sufficient information to accurately determine location/

quality differentials, with relatively rare exceptions.

If a lessee disposes of its oil through one or more exchange

agreements, it ordinarily should have the information necessary to

determine adjustments to the index price. If the oil is not disposed of

through exchange agreements, then the lessee is physically transporting

the oil either to a market center or to an alternate disposal point

(such as a refinery.) In that event, the lessee would have the

necessary information regarding actual transportation costs to claim

the appropriate transportation allowance.

As a result of eliminating MMS-published differentials, the

proposed Form MMS-4415 is eliminated from this proposal. Therefore, it

is not necessary to address the extensive comments MMS received

regarding the content and timing of the form.

Paragraph 206.112(a) of this supplementary proposed rule would

cover situations where you dispose of your production under one or more

arm's-length exchange agreements. In this case, you would adjust the

index price for any location/quality differentials that reflect the

difference in value of crude oil between the point(s) where your

production is given in exchange and the point(s) where oil is received

in exchange. You could also adjust the index price to reflect any

actual transportation costs between the lease and the first point where

you give your oil in exchange, and between any intermediate point where

you receive oil in exchange to another point where you give the oil in

exchange again, and between the last point you receive oil in exchange

and a market center or refinery that is not at a market center. These

costs would be determined under Secs. 206.110 or 206.111, depending on

whether your transportation arrangement is at arm's length or not.

(Note again, that if the transportation costs from the lease to the

market center or alternate disposal point are already reflected in the

location differential between the lease and the market center, you

could not claim duplicate transportation costs.) A third adjustment

discussed below (paragraph (d)) could be warranted if the quality of

your lease production differs from that of the oil you exchanged at any

intermediate point (for example, due to commingling at intermediate

locations). This last adjustment would be based on pipeline quality

bank premia or penalties, but only if such quality banks exist at

intermediate commingling points before your oil reaches the market

center or alternate disposal point.

For example, Company A transports its production from a platform in

the Gulf of Mexico to an intermediate point under an arm's-length

transportation contract for $0.50 per barrel. Company A then enters

into an arm's-length exchange agreement between the intermediate point

and the market center at St. James, Louisiana. Company A then refines

the oil it receives at the market center, so it would have to determine

value using an index price under Sec. 206.103. The arm's-length

exchange agreement between the intermediate point and St. James

contains a location/quality differential of $0.10 per barrel. The

average of the daily mean spot prices for St. James (the market center

nearest the lease with crude oil most similar in quality to Company A's

oil) is $20.00 per barrel for deliveries during the production month.

The value of Company A's production at the lease would be $19.40

($20.00--$0.10--$0.50) per barrel.

Under paragraph 206.112(a), you would have to determine the

differentials from each of your arm's-length exchange agreements

applicable to the exchanged oil. Therefore, for example, if you

exchange 100 barrels of production under two separate arm's-length

exchange agreements for 60 barrels and 40 barrels respectively, you

would separately determine the location/quality differential under each

of those exchange agreements, and

[[Page 73836]]

apply each differential to the corresponding index price.

As another example, if you produce 100 barrels and exchange that

100 barrels three successive times under arm's-length agreements to

obtain oil at a final destination, you would total the three

adjustments from those exchanges to determine the adjustment under this

subparagraph. (If one of the three exchanges were not at arm's length,

you would have to request MMS approval under paragraph (b) for the

location/quality adjustment for that exchange to determine the total

location/quality adjustment for the three exchanges.) You also could

have a combination of these examples.

Proposed paragraph 206.112(b) addresses cases where your exchange

agreement is not at arm's-length. In that case, you must request

approval from MMS for any location/quality adjustment.

Paragraph 206.112(c) would address cases where you transport your

production directly to a market center or to an alternate disposal

point (for example, your refinery), and establish value based on index

prices under Sec. 206.103.

In the case of transportation directly to a refinery, you would

deduct from the index price your actual costs of transporting

production from the lease to the refinery with the costs determined

under Secs. 206.110 or 206.111 and any quality adjustments determined

by pipeline quality banks under paragraph 206.112(d). The index pricing

point would be the one nearest the lease.

For example, a lessee or its affiliate in the Gulf of Mexico might

transport its production directly to a refinery on the eastern coast of

Texas and not to an index pricing point. Because that production is not

sold at arm's length, the lessee would have to base value on the

average of the daily mean spot prices for St. James, less actual costs

of transporting the oil to the refinery and any quality adjustments

from the lease to the refinery.

Likewise, if a lessee or its affiliate transports Wyoming sour

crude oil directly to its refinery in Salt Lake City, Utah, and values

the oil based on paragraph 206.103(b)(3), the lessee would have to base

value on the average of the daily Cushing spot prices, less the actual

cost of transporting the oil to Salt Lake City and any quality

adjustments between the lease and the refinery.

When production is moved directly to a refinery and value must be

established using an index, issues arise because the refinery generally

is not located at an index pricing point. Consequently, the lessee does

not incur actual costs to transport production to an index pricing

point, and in any event, the production is not sold at arm's length at

that point. The principle underlying the rules and cases granting

allowances for transportation costs is that the lessee is not required

to transport production to a market remote from the lease or field at

its own expense. When the lessee sells production at a remote market,

the costs of transporting to that market are deductible from value at

that market to determine the value of the production at or near the

lease. Where sales occur only at or near the lease, the question of a

transportation allowance, as that term always has been understood, does

not arise. However, because the lease and the index pricing point may

be distant from one another, there is a difference in the value of the

production between the index pricing point and the lease location. The

question becomes how to determine or how best to approximate that

difference in value.

In theory, one solution would be for MMS to try to derive what it

would cost a lessee to move production from the lease to the index

pricing point. There are, in MMS's view, several problems with such an

approach. First, it would require a burdensome information collection

from industry and impose substantial information collection costs on

many parties to whom the resulting calculation may never be relevant.

Second, in many cases it may well not be possible to obtain information

on which to base such a calculation. In many instances, it is likely

that no production from the lease or field is transported to the index

pricing point that applies under Sec. 206.103. Consequently, in such

cases there would be no useful data on which such a cost derivation

could be based.

Another possible solution, in theory, would be for MMS to derive a

location adjustment between the index pricing point and the refinery.

This might be possible if, for example, there are arm's-length

exchanges of significant volumes of oil between the index pricing point

and the refinery, and if the exchange agreements provide for location

adjustments that can be separated from quality adjustments. But

establishing such location adjustments on any scale again would require

a burdensome information collection effort. MMS also anticipates that

in many cases there would be no useful data from which to derive a

location adjustment.

MMS therefore believes that the best and most practical proxy

method for determining the difference in value between the lease and

the index pricing point is to use the index price as value at the

refinery, and then allow the lessee to deduct the actual costs of

moving the production from the lease to the refinery. This is not a

``transportation allowance'' as that term is commonly understood, but

rather is part of the methodology for determining the difference in

value due to the location difference between the lease and the index

pricing point. Nevertheless, it is appropriate to include this

deduction for situations in which index pricing is used.

MMS included this same method in the January 1997 proposal and did

not receive any suggestions for alternative methods. We received few

comments on this issue in response to the February 1998 proposal.

However, one State commented that this method could result in

calculation of inappropriate differentials. Absent better alternatives,

MMS believes this method is the best and most reasonable way to

calculate the differences in value due to location when production is

not actually moved from the lease to an index pricing point.

However, if a lessee believes that applying the index price nearest

the lease to production moved directly to a refinery results in an

unreasonable value based on circumstances of the lessee's production,

paragraph 206.103(e) would allow MMS to approve an alternative method

if the lessee could demonstrate the market value at the refinery.

Although we received a few comments that MMS should not allow such

requests, MMS believes it should leave this opportunity open for those

limited cases where the procedure discussed above may be shown to be

inappropriate. MMS would do a thorough review and analysis of any such

requests and would only approve them where the proper alternative value

or procedure has been clearly demonstrated.

It would be the lessee's burden to provide adequate documentation

and evidence demonstrating the market value at the refinery. That

evidence could include, but not be limited to: (1) Costs of acquiring

other crude oil at or for the refinery; (2) how adjustments for

quality, location, and transportation were factored into the price paid

for the other oil; (3) the volumes acquired for the refinery; and (4)

other appropriate evidence or documentation that MMS would require. If

MMS approved an alternative value representing market value at the

refinery, there would be no deduction for the costs of transporting the

oil to the refinery unless specifically identified in the Director's

approval. Whether any quality adjustment is available would depend on

whether the oil passes through a pipeline quality

[[Page 73837]]

bank or if an arm's-length exchange agreement used to get oil to the

refinery contains a separately-identifiable quality adjustment.

Paragraph 206.112(c) would also cover situations where you

transport your oil directly to an MMS-identified market center. To

arrive at the royalty value, you would adjust the index price by your

actual costs of transportation under Secs. 206.110 and 206.111. A

second adjustment discussed below (paragraph (d)) may be warranted if

the quality of your lease production differs from the quality of the

oil at the market center. This adjustment would be based on pipeline

quality bank premia or penalties, but only if such quality banks exist

at intermediate commingling points before your oil reaches the market

center.

For example, Company A transports its production from a platform in

the Gulf of Mexico to St. James, Louisiana, under a non-arm's-length

transportation contract with its affiliate. The actual cost of

transporting production under Sec. 206.111 is $0.50 per barrel. The

average of the daily spot prices at St. James is $20.00 per barrel for

deliveries during the production month. The value of Company A's

production at the lease would be $19.50 ($20.00--$0.50) per barrel.

In the February 1998 proposal at paragraph 206.112(e), and in this

proposal at paragraph 206.112(d), MMS added a separate adjustment to

reflect quality differences based on quality banks between your lease

and an alternate disposal point or market center applicable to your

lease. You would make these quality adjustments according to the

pipeline quality bank specifications and related premia or penalties

that may apply in your specific situation. If no pipeline quality bank

applies to your production, then you would not take this quality

adjustment. Likewise, if a quality adjustment is already contained in

an arm's-length exchange agreement from the lease to the market center,

you could not also claim a pipeline quality bank adjustment from the

lease to an intermediate point or the market center. MMS believes this

additional adjustment would more accurately reflect actual quality

adjustments made by buyers and sellers.

Also, in the absence of a quality bank, the proposal does not

provide for any adjustments for quality differences between the indexed

crude oil and the oil produced at the lease. MMS intentionally limited

such adjustments only to those cases where a quality bank applies to

the lessee's production. MMS does not want to be in a position of

permitting quality adjustments where they may not be warranted.

Further, quality adjustments would be reflected in the location

differentials applied by lessees from their arm's-length exchange

agreements.

In this proposal, paragraph 206.112(e) contains language from

proposed paragraph 206.112(f) of the February 1998 proposal. It states

that the term ``market center'' means Cushing, Oklahoma, when

determining location/quality differentials and transportation

allowances for production from leases in the Rocky Mountain Region.

Paragraph 206.112(f) of this proposal addresses situations where

you may not have access to differentials between the lease and the

alternate disposal point or market center, or you may not have access

to the actual transportation costs from the lease to the alternate

disposal point or market center. In such cases, which should be

infrequent, MMS would permit you to request approval for a

transportation allowance or quality adjustment. In determining the

allowance for transportation from the lease to the alternate disposal

point or market center, MMS would look to transportation costs and

quality adjustments reported for other oil production in the same field

or area, or to available information for similar transportation

situations. Under paragraph 206.112(b), you also would have to request

approval from MMS for any location/quality adjustments when you have a

non-arm's-length exchange agreement.

In this proposal, we added a new paragraph (g) to Sec. 206.112 to

clarify that regardless of how you dispose of your production and which

adjustments might otherwise apply, you would not be able to use any

transportation or quality adjustment that duplicates all or part of any

other adjustment that you use under Sec. 206.112. Moreover, the

structure of the proposal is not susceptible to the problem of ``double

dipping'' quality adjustments as described by one commenter. Under this

proposal, for example, if you disposed of your production under an

arm's-length exchange agreement, but transported the oil away from the

lease to an intermediate point before giving it in exchange, you would

not be able to claim a transportation allowance between the point where

you gave the oil in exchange and the point you received oil back in

exchange if you used a location differential for the segment between

those two points.

This same principle would apply for all adjustments addressed in

Sec. 206.112. That is, any time a lessee took one of the listed

adjustments, it could not duplicate any portion of that adjustment as

part or all of any other adjustment that otherwise would be allowable.

Section 206.113 How Will MMS Identify Market Centers?

Proposed section 206.113 is paragraph 206.105(c)(8) of the January

1997 proposal and Section 206.115 of the February 1998 proposal except

that we have eliminated the identification of aggregation points and

made minor wording changes. MMS proposes to eliminate the list of

aggregation points identified in the January 1997 proposal in

conjunction with the elimination of Form MMS-4415.

In the preamble to the January 1997 proposal, MMS listed market

centers for purposes of the rule. That list included Guernsey, Wyoming.

MMS proposes to eliminate Guernsey as a market center for the reasons

given earlier. Also, we received comments that simply using Los Angeles

and San Francisco as market centers for ANS pricing purposes was too

broad and that multiple, local delivery points in and near these two

cities should be included in the market center definition. So, for

purposes of this rulemaking, the Los Angeles market center would

includes Hines Station, GATX Terminal, and any of the refineries

located in Los Angeles County. The San Francisco market center would

include Avon, or any of the refineries located in Contra Costa or

Solano Counties.

Section 206.114 What Are My Reporting Requirements Under an Arm's-

Length Transportation Contract?

Proposed Section 206.114 is paragraph 206.105(c)(1) of the existing

rule rewritten in plain English, and is the same as Section 206.116 in

the February 1998 proposal.

Section 206.115 What Are My Reporting Requirements Under a Non-Arm's-

Length Transportation Contract?

Proposed Section 206.115 is paragraph 206.105(c)(2) of the existing

rule rewritten in plain English, except paragraph 206.105(c)(2)(iv) is

deleted as described in the preamble to the January 1997 proposal. This

also corresponds to Section 206.117 in the February 1998 proposal.

Section 206.116 What Interest and Assessments Apply If I Improperly

Report a Transportation Allowance?

Section 206.116 of this proposal is paragraph 206.105(d) of the

existing rule rewritten in plain English, and also corresponds to

Section 206.119 of the February 1998 proposal.

[[Page 73838]]

Section 206.117 What Reporting Adjustments Must I Make for

Transportation Allowances?

Section 206.117 of this proposal is paragraph 206.105(e) of the

existing rule rewritten in plain English, and corresponds to Section

206.120 of the February 1998 proposal.

Section 206.118 Are Costs Allowed for Actual or Theoretical Losses?

Section 206.118 of this proposal is paragraph 206.105(f) of the

existing rule rewritten in plain English, and corresponds to Section

206.121 of the February 1998 proposal. Reference to the FERC- or State

regulatory agency-approved tariffs was deleted in the January 1997

proposal, as it is in this proposal. Although we received a comment

that actual or theoretical losses are real costs of transportation,

this section would simply continue longstanding policy.

Section 206.119 How Are the Royalty Quantity and Quality Determined?

Section 206.119 of this proposal is Sec. 206.103 of the existing

rule rewritten in plain English, and corresponds to Section 206.122 of

the February 1998 proposal.

Section 206.120 How Are Operating Allowances Determined?

Section 206.120 of this proposal is Sec. 206.106 of the existing

rule rewritten in plain English, and corresponds to Section 206.123 of

the February 1998 proposal.

V. Procedural Matters

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.

You may also comment via the Internet to www.rmp.mms.gov. Please

submit Internet comments as an ASCII file avoiding the use of special

characters and any form of encryption. Please also include Attn:

Further Supplementary Proposed Rulemaking Establishing Oil Value for

Royalty Due on Federal Leases, and your name and return address in your

Internet message. If you do not receive a confirmation from the system

that we have received your Internet message, contact David S. Guzy

directly at (303) 231-3432.

We will post public comments after the comment period closes on the

Internet at www.rmp.mms.gov. You may arrange to view paper copies of

the comments by contacting David S. Guzy, Chief, Rules and Publications

Staff, telephone (303) 231-3432, FAX (303) 231-3385.

Executive Order 12866

In accordance with the criteria in Executive Order 12866, this

further supplementary proposed 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 further

supplementary proposed rule because it raises novel legal or policy

issues.

This further supplementary proposed rule would not have an annual

effect of $100 million or adversely affect an economic sector,

productivity, jobs, the environment, or other units of Government. We

estimate that the economic impact of this further supplementary

proposed rule would be about $63.5 million. This estimate represents

the net impact of the proposal accounting for both estimated costs and

benefits. This proposal would not create inconsistencies with other

agencies' actions and would not materially affect entitlements, grants,

user fees, loan programs, or the rights and obligations of their

recipients.

The Regulatory Flexibility Act

The Department of the Interior certifies that this document will

not have a significant economic effect on a substantial number of small

entities under the Regulatory Flexibility Act (5 U.S.C. 601 et seq.).

Accordingly, a Small Entity Compliance Guide is not required. This

proposed rule would not affect a substantial number of small

businesses. Approximately 800 businesses pay royalties to MMS on oil

produced from Federal leases. MMS believes only 45 of the 800 total

payors would pay additional royalties under this proposed rule. We

further believe that only nine of those 45 payors are small businesses

as defined by the U.S. Small Business Administration. MMS further

estimates that 97 percent of the remaining 755 payors, or 732, would be

considered small businesses. The nine payors that we consider small

businesses that would be affected by the rule make up less than 1.15

percent of all the payors reporting to MMS on oil produced from Federal

leases and less than 1.25 percent of all the small businesses reporting

to MMS on oil produced from Federal leases. A Regulatory Analysis is

available upon request.

Small Business Regulatory Enforcement Fairness Act (SBREFA)

This further supplementary proposed 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; and

(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.

Unfunded Mandates Reform Act of 1995

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. This rule would not change the relationship between MMS, and

State, local, or tribal governments. A statement containing the

information required by the Unfunded Mandates Reform Act (2 U.S.C. 1531

et seq.) is not required.

Executive Order 12630

MMS received a comment on the February 1998 proposal that the

proposed rule deprives lessees of their constitutionally protected

property rights when royalties are paid based on a higher than actual

lease sales price. This is a price that the lessee would find

impossible to actually realize because it includes returns on

investments and on downstream marketing profits. The commenter asserted

that because such a taking would occur if the rule is approved, MMS

must prepare a Takings Implication Assessment pursuant to Executive

Order 12630.

The guidelines under Executive Order 12630 require a Federal agency

to justly compensate a private property owner if private property is

taken for public use. Disagreements over methods of valuing production

for royalty purposes do not change the property relationship

[[Page 73839]]

between a lessee and the Federal lessor, and do not operate to deprive

the lessee of any property interest. Even if a particular valuation

method is held to be unlawful or unauthorized, the remedy is to

overturn the unauthorized agency action. This does not have

constitutional takings implications.

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.

Executive Order 13132 (Federalism)

In accordance with Executive Order 13132, this further

supplementary proposed rule does not have Federalism implications. The

management of Federal leases is the responsibility of the Secretary of

the Interior. Royalties collected from Federal leases are shared with

State governments on a percentage basis as prescribed by law. This

further supplementary proposed rule would not alter any lease

management or royalty sharing provisions. It would determine the value

of production for royalty computation purposes only. This further

supplementary proposed rule would not impose costs on States or

localities. Costs associated with the management, collection and

distribution of royalties to States and localities are currently shared

on a revenue receipt basis. This further supplementary proposed rule

would not alter that relationship.

Executive Order 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 meets the requirements of Secs. 3(a) and 3(b)(2) of

the Order.

Paperwork Reduction Act

Under the Paperwork Reduction Act of 1995, we are soliciting

comments on information collections which are associated with this

further supplementary proposed rulemaking establishing oil value for

royalty due on federal leases. Written comments should be received on

or before January 31, 2000.

If you wish to comment, please send your comments directly to the

Office of Information and Regulatory Affairs, OMB, Attention: Desk

Officer for the Interior Department (OMB Control Number 1010-NEW), 725

17th Street, NW, Washington, D.C. 20503.

You should also send copies of these comments to us. You may mail

comments to David S. Guzy, Chief, Rules and Publications Staff,

Minerals Management Service, Royalty Management Program, P.O. Box

25165, MS 3021, Denver, CO 80225-0165. Courier or overnight delivery

address is Building 85, Room A-613, Denver Federal Center, Denver,

Colorado 80225.

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.

For all of the following information collections, we estimate that

there will be 45 respondents who will submit 85 responses. The

frequency of response varies by rulemaking section. We estimate the

annual proposed burden to be 17,711.5 hours. Based on $50 per hour, the

total cost would be $885,575. For estimating the burden on industry, we

divided the information collection requirements of the further

supplementary proposed rule into five areas. A table for each of the

areas and specific details follow:

a. Proper Valuation of Oil Not Sold at Arm's-Length

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

Annual

30 CFR 206, subpart D Reporting & recordkeeping Frequency Number of Burden burden

requirements respondents hours

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

206.103............................. Calculate value of oil not Monthly..................... 45 Category 1--222.5 hours; 4,231.5

sold at arm's-length. Category 2--116 hours;

Category 3--31.25 hours.

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

For the reporting requirements associated with Section 206.103, we

estimate that there are 45 respondents (lessees of Federal oil leases)

that will be required to perform certain calculations and adjustments

monthly. We estimate that the total initial burden for all lessees

without arm's-length transactions is 4,231.5 hours at a cost of

$211,575.

We anticipate that companies would have to sort through their

exchange agreement contracts before the relevant ones can be compiled

and the required information extracted and used in their royalty

computations. We believe the further supplementary proposed rule would

impact approximately 45 Federal oil lessees that would be required to

use index pricing. For purposes of estimating the burden impact of this

further supplementary proposed rule, we have categorized these lessees

into three categories:

Category 1 lessees are companies with over 30 million barrels of

annual production (this included 13 Federal lessees from our impact

analysis).

Category 2 lessees are companies with annual domestic production

between 10 and 30 million barrels (this included four Federal lessees

from our impact analysis).

Category 3 lessees are companies with less than 10 million barrels

of annual domestic production (this included 28 Federal lessees from

our impact analysis).

We estimate that Category 1 lessees each would have approximately

1,000 exchange agreement contracts to review to identify the relevant

contracts needed for proper valuation under this further supplementary

proposed rule. Of those contracts, we estimate that each company would

have to use 250 exchange agreements in its royalty reporting. We

estimate that the reporting burden for a Category 1 company is 222.5

hours, including 80 hours to aggregate the exchange agreement contracts

to a central location, 80 hours to sort and identify the relevant ones,

and 62.5 additional hours to extract the relevant information and apply

it in reporting royalties. We estimate the total reporting burden for

the 13 Category 1 companies would be 2,892.5 hours (222.5 hours x 13

companies), including recordkeeping; using a per-hour cost of $50, the

total cost would be $144,625.

We estimate that Category 2 lessees each would have approximately

250

[[Page 73840]]

exchange agreement contracts to review to identify the relevant

contracts needed for valuation under this further supplementary

proposed rule. Of those contracts, we estimate that each Category 2

company would have to use 63 exchange agreements. We estimate that the

reporting burden for a Category 2 company would be 116 hours, including

60 hours to aggregate the exchange agreement contracts to a central

location, 40 hours to sort them, and 16 additional hours to extract the

relevant information and apply it in reporting royalties. For the 4

Category 2 companies, we estimate the total burden would be 464 hours

(116 hours x 4 companies), including recordkeeping; using a per-hour

cost of $50, the total cost would be $23,200.

We estimate that Category 3 lessees each would have approximately

50 exchange agreements to review to identify the relevant contracts

needed for valuation under this further supplementary proposed rule. Of

those contracts, we estimate that each Category 3 company would have to

use 13 exchange agreements. We estimate that the burden for each

Category 3 company would be 31.25 hours, including 20 hours to

aggregate the exchange agreement contracts to a central location, 8

hours to sort them, and 3.25 additional hours to extract the relevant

information and apply it in reporting royalties. For the 28 Category 3

companies, we estimate that the burden would be 875 hours (31.25 hours

x 28 companies), including recordkeeping; using a per-hour cost of $50,

the total cost would be $43,750.

We expect the annual burden to decline somewhat as industry becomes

more familiar with the proposed valuation requirements.

b. Approval of Benchmarks in the Rocky Mountain Region

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

Reporting & Annual

30 CFR 206, subpart D recordkeeping Frequency Number of Burden burden

requirements responses (hours) hours

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

206.103(b)(1)................ Obtain MMS approval 1-2 annually........ 2 400 800

for tendering

program.

206.103(b)(4)................ Obtain MMS approval 1-2 annually........ 2 400 800

for alternative

valuation

methodology.

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

For the reporting requirements related to MMS approval of using the

benchmarks, we estimate that there will be two responses for each of

the two reporting requirements. On occasion, they will be required to

submit requests to us in writing.

We anticipate that a lessee will undertake the following four steps

in the formulation of specifics surrounding a tendering program or

alternate valuation strategy: (1) formulation of valuation methodology:

100 hours, (2) economic evaluation of methodology: 100 hours, (3) legal

review of methodology: 150 hours, and (4) presentation to MMS: 50

hours, for a total of 400 hours.

We anticipate four requests a year for an annual burden of 1,600

hours, including recordkeeping. Based on a per-hour cost of $50, we

estimate that the cost to industry is $80,000.

c. Requirements Related to Requested Valuation Determinations and

Approval of Location/Quality Adjustments From MMS

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

Reporting & Annual

30 CFR 206, subpart D recordkeeping Frequency Number of Burden burden

requirements responses (hours) hours

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

206.107(a)(1)-(6)............ Request a value 1-2 monthly......... 8 330 2,640

determination from

MMS.

206.112(b)................... Request MMS approval 1-2 monthly......... 8 330 2,640

for location/

quality adjustment

under non-arm's-

length exchange

agreements.

206.112(f)................... Request MMS for 1-2 monthly......... 8 330 2,640

location/quality

adjustment when

information is not

available.

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

We anticipate that the companies may request guidance on how

royalty statutes, regulations, administrative decisions, and policies

apply to a specific set of facts. Their requests would have to: (1) be

in writing; (2) identify specifically all leases involved, the record

title or operating rights owners of those leases, and the designees for

those leases; (3) completely explain all relevant facts. They must

inform MMS of any changes to relevant facts that occur before MMS

responds to their request; (4) include copies of all relevant

documents; (5) provide their analysis of the issue(s), including

citations to all relevant precedents (including adverse precedents);

and (6) suggest their proposed valuation method.

For the above written requests, we estimate that there will be

eight responses annually for each of the reporting requirements. We

estimate the annual burden for each of these is 2,640 hours, including

recordkeeping. Based on a per-hour cost of $50, we estimate the cost to

industry is $132,000. The total burden is estimated at 7,920 hours and

$396,000.

d. Requirements Related to Special Requests Due to Unique Circumstances

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

Reporting & Annual

30 CFR 206, subpart D recordkeeping Frequency Number of Burden burden

requirements responses (hours) hours

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

206.103(e)(1) and (2)(i)-(iv) Obtain MMS approval 1-2 annually........ 2 330 660

to use value

determined at

refinery.

206.110(b)(2)................ Propose 1-2 annually........ 2 330 660

transportation cost

allocation method

to MMS when

transporting more

than one liquid

product under an

arm's-length

contract.

[[Page 73841]]

206.110(c)(1) and (3)........ Propose 1-2 annually........ 2 330 660

transportation cost

allocation method

to MMS when

transporting

gaseous and liquid

products under an

arm's-length

contract.

206.111(g) and (g)(1)........ Elect actual 1-2 annually........ 2 330 660

transportation cost

method and

depreciation method

for non-arm's-

length

transportation

allowances.

206.111(i)(2)................ Propose 1-2 annually........ 2 330 660

transportation cost

allocation method

to MMS when

transporting more

than one liquid

product under a non-

arm's-length

contract.

206.111(j)(1) and (3)........ Propose 1-2 annually........ 2 330 660

transportation cost

allocation method

to MMS when

transporting

gaseous and liquid

product under a non-

arm's-length

contract..

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

There are several provisions in the further supplementary proposed

rule that allow the lessee to propose some special consideration

because the existing provisions of the rule may not precisely fit their

situation. Like the written requests outlined above, their requests

would have to: (1) be in writing; (2) identify specifically all leases

involved, the recor

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