[Federal Register Volume 64, Number 250 (Thursday, December 30, 1999)]
[Proposed Rules]
[Pages 73820-73849]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 99-33613]



[[Page 73819]]

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Part IV





Department of the Interior





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Minerals Management Service



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30 CFR Part 206



Establishing Oil Value for Royalty Due on Federal Leases; Proposed Rule

  Federal Register / Vol. 64, No. 250 / Thursday, December 30, 1999 / 
Proposed Rules  

[[Page 73820]]



DEPARTMENT OF THE INTERIOR

Minerals Management Service

30 CFR Part 206

RIN 1010-AC09


Establishing Oil Value for Royalty Due on Federal Leases

AGENCY: Minerals Management Service, Interior.

ACTION: Further supplementary proposed rule.

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SUMMARY: The Minerals Management Service (MMS) is proposing further 
changes to its proposed rulemaking regarding the valuation, for royalty 
purposes, of crude oil produced from 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 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 reporting requirements related to special requests because 
of unique circumstances, we estimate that there will be two responses 
for each of the six situations above. We estimate the annual burden for 
each of these is 660 hours, including recordkeeping. Based on a per-
hour cost of $50, we estimate the cost to industry is $33,000. The 
total burden is estimated to be 3,960 hours and $198,000.
e. Currently Approved Information Collections

----------------------------------------------------------------------------------------------------------------
                                    Reporting &                                                         Annual
    30 CFR 206, subpart D          recordkeeping           Frequency        Number of      Burden       burden
                                   requirements                             responses     (hours)       hours
----------------------------------------------------------------------------------------------------------------
206.105......................  Retain all records      Burden covered under OMB Control No. 1010-
                                showing how value                         0061.
                                was determined.
206.109(c)(2)................  Request to exceed       Burden covered under OMB Control No. 1010-
                                regulatory limit--                        0095.
                                Form MMS-4393.
206.114 and 115(a)...........  Report a separate       Burden covered under OMB Control No. 1010-
                                line for                                  0022.
                                transportation
                                allowances--Form
                                MMS-2014.
206.114 and 115(c)...........  Submit                  Burden covered under OMB Control No. 1010-
                                transportation                            0061.
                                documents upon MMS
                                request.
----------------------------------------------------------------------------------------------------------------

National Environmental Policy Act of 1969

    This rule would not constitute a major Federal action significantly 
affecting the quality of the human environment. A detailed statement 
under the National Environmental Policy Act of 1969 is not required.

Clarity of This Regulation

    Executive Order 12866 requires each agency to write regulations 
that are easy to understand. We invite your comments on how to make 
this rule easier to understand, including answers to questions such as 
the following: (1) Are the requirements in the rule clearly stated? (2) 
Does the rule contain technical language or jargon that interferes with 
this clarity? (3) Does the format of the rule (grouping and order of 
sections, use of headings, paragraphing, etc.) aid or reduce its 
clarity? (4) Would the rule be easier to understand if it were divided 
into more (but shorter) sections? (A ``section'' appears in bold type 
and is preceded by the symbol ``Sec. '' and a numbered heading; for 
example Sec. 206.100.) (5) Is the description of the rule in the 
``Supplementary Information'' section of the preamble helpful in 
understanding the rule? What else could we do to make the rule easier 
to understand?
    Send a copy of any comments that concern how we could make this 
rule easier to understand to: Office of Regulatory Affairs, Department 
of the Interior, Room 7229, 1849 C Street NW, Washington, DC 20240. You 
may also e-mail the comments to this address: E[email protected].

List of Subjects 30 CFR Part 206

    Coal, Continental shelf, Geothermal energy, Government contracts, 
Indians--lands, Mineral royalties, Natural gas, Petroleum, Pubic 
lands--mineral resources, Reporting and recordkeeping requirements.

    Dated December 22, 1999.
Sylvia V. Baca,
Assistant Secretary for Land and Minerals Management.

    For the reasons given in the preamble, 30 CFR Part 206 is proposed 
to be amended as set forth below:

PART 206--PRODUCT VALUATION

    1. The authority citation for Part 206 continues to read as 
follows:

    Authority: 5 U.S.C. 301 et seq.; 25 U.S.C. 396 et seq., 396a et 
seq.; 2101 et seq.; 30 U.S.C. 181 et seq., 351 et seq., 1001 et 
seq., 1701 et seq.; 31 U.S.C. 9701; 43 U.S.C. 1301 et seq., 1331 et 
seq., and 1801 et seq.

    2. Subpart C--Federal Oil is revised to read as follows:

Subpart C--Federal Oil

Sec.
206.100  What is the purpose of this subpart?
206.101  Definitions.

[[Page 73842]]

206.102  How do I calculate royalty value for oil that I or my 
affiliate sell(s) under an arm's-length contract?
206.103  How do I value oil that is not sold under an arm's-length 
contract?
206.104  What index price publications are acceptable to MMS?
206.105  What records must I keep to support my calculations of 
value under this subpart?
206.106  What are my responsibilities to place production into 
marketable condition and to market production?
206.107  How do I request a value determination?
206.108  Does MMS protect information I provide?
206.109  When may I take a transportation allowance in determining 
value?
206.110  How do I determine a transportation allowance under an 
arm's-length transportation contract?
206.111  How do I determine a transportation allowance under a non-
arm's-length transportation arrangement?
206.112  What adjustments and transportation allowances apply when I 
value oil using index pricing?
206.113  How will MMS identify market centers?
206.114  What are my reporting requirements under an arm's-length 
transportation contract?
206.115  What are my reporting requirements under a non-arm's-length 
transportation contract?
206.116  What interest and assessments apply if I improperly report 
a transportation allowance?
206.117  What reporting adjustments must I make for transportation 
allowances?
206.118  Are costs allowed for actual or theoretical losses?
206.119  How are the royalty quantity and quality determined?
206.120  How are operating allowances determined?

Subpart C--Federal Oil


Sec. 206.100  What is the purpose of this subpart?

    (a) This subpart applies to all oil produced from Federal oil and 
gas leases onshore and on the Outer Continental Shelf (OCS). It 
explains how you as a lessee must calculate the value of production for 
royalty purposes consistent with the mineral leasing laws, other 
applicable laws, and lease terms. If you are a designee and if you 
dispose of production on behalf of a lessee, the terms ``you'' and 
``your'' in this subpart refer to you. If you are a designee and only 
report for a lessee, and do not dispose of the lessee's production, 
references to ``you'' and ``your'' in this subpart refer to the lessee 
and not the designee. Accordingly, you as a designee must determine and 
report royalty value for the lessee's oil by applying the rules in this 
subpart to the lessee's disposition of its oil.
    (b) If the regulations in this subpart are inconsistent with:
    (1) A Federal statute;
    (2) A settlement agreement between the United States and a lessee 
resulting from administrative or judicial litigation; or
    (3) An express provision of an oil and gas lease subject to this 
subpart, then the statute, settlement agreement, or lease provision 
will govern to the extent of the inconsistency.
    (c) MMS may audit and adjust all royalty payments.


Sec. 206.101  Definitions.

    The following definitions apply to this subpart:
    Affiliate means 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 constitutes control. Ownership of less 
than 10 percent constitutes a presumption of noncontrol that 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 will 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, are affiliates.
    ANS means Alaska North Slope (ANS).
    Area means a geographic region at least as large as the limits of 
an oil field, in which oil has similar quality, economic, and legal 
characteristics.
    Arm's-length contract means 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 must satisfy this 
definition for that month, as well as when the contract was executed.
    Audit means a review, conducted under generally accepted accounting 
and auditing standards, of royalty payment compliance activities of 
lessees, designees or other persons who pay royalties, rents, or 
bonuses on Federal leases.
    BLM means the Bureau of Land Management of the Department of the 
Interior.
    Condensate means liquid hydrocarbons (normally exceeding 40 degrees 
of API gravity) recovered at the surface without processing. Condensate 
is the mixture of liquid hydrocarbons resulting from condensation of 
petroleum hydrocarbons existing initially in a gaseous phase in an 
underground reservoir.
    Contract means any oral or written agreement, including amendments 
or revisions, between two or more persons, that is enforceable by law 
and that with due consideration creates an obligation.
    Designee means the person the lessee designates to report and pay 
the lessee's royalties for a lease.
    Exchange agreement means an agreement where one person agrees to 
deliver oil to another person at a specified location in exchange for 
oil deliveries at another location. Exchange agreements may or may not 
specify prices for the oil involved. They frequently specify dollar 
amounts reflecting location, quality, or other differentials. Exchange 
agreements include buy/sell agreements, which specify prices to be paid 
at each exchange point and may appear to be two separate sales within 
the same agreement. Examples of other types of exchange agreements 
include, but are not 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.
    Field means a geographic region situated over one or more 
subsurface oil

[[Page 73843]]

and gas reservoirs and encompassing at least the outermost boundaries 
of all oil and gas accumulations known within those reservoirs, 
vertically projected to the land surface. State oil and gas regulatory 
agencies usually name onshore fields and designate their official 
boundaries. MMS names and designates boundaries of OCS fields.
    Gathering means the movement of lease production to a central 
accumulation or treatment point on the lease, unit, or communitized 
area, or to a central accumulation or treatment point off the lease, 
unit, or communitized area that BLM or MMS approves for onshore and 
offshore leases, respectively.
    Gross proceeds means the total monies and other consideration 
accruing for the disposition of oil produced. Gross proceeds also 
include, but are not limited to, the following examples:
    (1) Payments for services such as dehydration, marketing, 
measurement, or gathering which the lessee must perform at no cost to 
the Federal Government;
    (2) The value of services, such as salt water disposal, that the 
producer normally performs but that the buyer performs on the 
producer's behalf;
    (3) Reimbursements for harboring or terminaling fees;
    (4) Tax reimbursements, even though the Federal royalty interest 
may be exempt from taxation;
    (5) Payments made to reduce or buy down the purchase price of oil 
to be produced in later periods, by allocating such payments over the 
production whose price the payment reduces and including the allocated 
amounts as proceeds for the production as it occurs; and
    (6) Monies and all other consideration to which a seller is 
contractually or legally entitled, but does not seek to collect through 
reasonable efforts.
    Index pricing means using ANS crude oil spot prices, West Texas 
Intermediate (WTI) crude oil spot prices at Cushing, Oklahoma, or other 
appropriate crude oil spot prices for royalty valuation.
    Index pricing point means the physical location where an index 
price is established in an MMS-approved publication.
    Lease means any contract, profit-share arrangement, joint venture, 
or other agreement issued or approved by the United States under a 
mineral leasing law that authorizes exploration for, development or 
extraction of, or removal of oil or gas--or the land area covered by 
that authorization, whichever the context requires.
    Lessee means any person to whom the United States issues an oil and 
gas lease, an assignee of all or a part of the record title interest, 
or any person to whom operating rights in a lease have been assigned.
    Location differential means an amount paid or received under an 
exchange agreement that results from differences in location between 
oil delivered in exchange and oil received in the exchange. A location 
differential may represent all or part of the difference between the 
price received for oil delivered and the price paid for oil received 
under a buy/sell exchange agreement.
    Market center means a major point MMS recognizes for oil sales, 
refining, or transshipment. Market centers generally are locations 
where MMS-approved publications publish oil spot prices.
    Marketable condition means oil sufficiently free from impurities 
and otherwise in a condition a purchaser will accept under a sales 
contract typical for the field or area.
    MMS-approved publication means a publication MMS approves for 
determining ANS spot prices, other spot prices, or location 
differentials.
    Netting means reducing the reported sales value to account for 
transportation instead of reporting a transportation allowance as a 
separate line on Form MMS-2014.
    Oil means a mixture of hydrocarbons that existed in the liquid 
phase in natural underground reservoirs, remains liquid at atmospheric 
pressure after passing through surface separating facilities, and is 
marketed or used as a liquid. Condensate recovered in lease separators 
or field facilities is considered oil.
    Outer Continental Shelf (OCS) means all submerged lands lying 
seaward and outside of the area of lands beneath navigable waters as 
defined in Section 2 of the Submerged Lands Act (43 U.S.C. 1301) and of 
which the subsoil and seabed appertain to the United States and are 
subject to its jurisdiction and control.
    Person means any individual, firm, corporation, association, 
partnership, consortium, or joint venture (when established as a 
separate entity).
    Quality differential means an amount paid or received under an 
exchange agreement that results from differences in API gravity, sulfur 
content, viscosity, metals content, and other quality factors between 
oil delivered and oil received in the exchange. A quality differential 
may represent all or part of the difference between the price received 
for oil delivered and the price paid for oil received under a buy/sell 
agreement.
    Rocky Mountain Region means the States of Colorado, Montana, North 
Dakota, South Dakota, Utah, and Wyoming.
    Sale means a contract between two persons where:
    (1) The seller unconditionally transfers title to the oil to the 
buyer and does not retain any related rights such as the right to buy 
back similar quantities of oil from the buyer elsewhere;
    (2) The buyer pays money or other consideration for the oil; and
    (3) The parties' intent is for a sale of the oil to occur.
    Spot price means the price under a spot sales contract where:
    (1) A seller agrees to sell to a buyer a specified amount of oil at 
a specified price over a specified period of short duration;
    (2) No cancellation notice is required to terminate the sales 
agreement; and
    (3) There is no obligation or implied intent to continue to sell in 
subsequent periods.
    Tendering program means 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.
    Transportation allowance means a deduction in determining royalty 
value for the reasonable, actual costs of moving oil to a point of sale 
or delivery off the lease, unit area, or communitized area. The 
transportation allowance does not include gathering costs.


Sec. 206.102  How do I calculate royalty value for oil that I or my 
affiliate sell(s) under an arm's-length contract?

    (a) The value of oil under paragraphs (a)(1) and (a)(2) of this 
section is the gross proceeds accruing to the seller under the arm's-
length contract, less applicable allowances determined under this 
subpart, unless you exercise an option provided in paragraph (d)(1) or 
(d)(2) of this section. See paragraph (c) of this section for 
exceptions. Use this paragraph (a) to value oil that:
    (1) You sell under an arm's-length sales contract; or
    (2) 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.
    (b) If you sell under multiple arm's-length contracts oil produced 
from a lease that is valued under paragraph (a) of this section, the 
value of the oil is the

[[Page 73844]]

volume-weighted average of the values established under this section 
for each contract for the sale of oil produced from that lease.
    (c) This paragraph contains exceptions to the valuation rule in 
paragraph (a) of this section. Apply these exceptions on an individual 
contract basis.
    (1) In conducting reviews and audits, if MMS determines that any 
arm's-length sales contract does not reflect the total consideration 
actually transferred either directly or indirectly from the buyer to 
the seller, MMS may require that you value the oil sold under that 
contract either under Sec. 206.103 or at the total consideration 
received.
    (2) You must value the oil under Sec. 206.103 if MMS determines 
that the value under paragraph (a) of this section does not reflect the 
reasonable value of the production due to either:
    (i) Misconduct by or between the parties to the arm's-length 
contract; or
    (ii) Breach of your duty to market the oil for the mutual benefit 
of yourself and the lessor.
    (A) 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.
    (B) 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, 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.
    (d)(1) If you enter into an arm's-length exchange agreement, or 
multiple sequential arm's-length exchange agreements, and following the 
exchange(s) you or your affiliate sell(s) the oil received in the 
exchange(s) under an arm's-length contract, then you may use either 
Sec. 206.102(a) or Sec. 206.103 to value your production for royalty 
purposes.
    (i) If you use Sec. 206.102(a), your gross proceeds are the gross 
proceeds under your or your affiliate's arm's-length sales contract 
after the exchange(s) occur(s). You must adjust your gross proceeds for 
any location or quality differential, or other adjustments, you 
received or paid under the arm's-length exchange agreement(s). If MMS 
determines that any arm's-length exchange agreement does not reflect 
reasonable location or quality differentials, MMS may require you to 
value the oil under Sec. 206.103. You may not otherwise use the price 
or differential specified in an arm's-length exchange agreement to 
value your production.
    (ii) When you elect under Sec. 206.102(d)(1) to use Sec. 206.102(a) 
or Sec. 206.103, you must make the same election for all of your 
production sold under arm's-length contracts following arm's-length 
exchange agreements, and you may not change your election more often 
than once every two years.
    (2)(i) If you sell or transfer your oil production to your 
affiliate and that affiliate or another affiliate then sells the oil 
under an arm's-length contract, you may use either Sec. 206.102(a) or 
Sec. 206.103 to value your production for royalty purposes.
    (ii) When you elect under Sec. 206.102(d)(2) to use Sec. 206.102(a) 
or Sec. 206.103, you must make the same election for all of your 
production that your affiliates resell at arm's length, and you may not 
change your election more often than once every two years.
    (e) If you value oil under paragraph (a) of this section:
    (1) MMS may require you to certify that your or your affiliate's 
arm's-length contract provisions include all of the consideration the 
buyer must pay, either directly or indirectly, for the oil.
    (2) You must base value on the highest price the seller can receive 
through legally enforceable claims under the contract.
    (i) If the seller fails to take proper or timely action to receive 
prices or benefits it is entitled to, you must pay royalty at a value 
based upon that obtainable price or benefit. But you will owe no 
additional royalties unless or until the seller receives monies or 
consideration resulting from the price increase or additional benefits, 
if:
    (A) The seller makes timely application for a price increase or 
benefit allowed under the contract;
    (B) The purchaser refuses to comply; and
    (C) The seller takes reasonable documented measures to force 
purchaser compliance.
    (ii) Paragraph (e)(2)(i) of this section will not permit you to 
avoid your royalty payment obligation where a purchaser fails to pay, 
pays only in part, or pays late. Any contract revisions or amendments 
that reduce prices or benefits to which the seller is entitled must be 
in writing and signed by all parties to the arm's-length contract.


Sec. 206.103  How do I value oil that is not sold under an arm's-length 
contract?

    This section explains how to value oil that you may not value under 
Sec. 206.102.
    (a) Production from leases in California or Alaska. Value is the 
average of the daily mean ANS spot prices published in any MMS-approved 
publication during the calendar month preceding the production month.
    (1) To calculate the daily mean spot price, average the daily high 
and low prices for the month in the selected publication.
    (2) Use only the days and corresponding spot prices for which such 
prices are published.
    (3) You must adjust the value for applicable location and quality 
differentials, and you may adjust it for transportation costs, under 
Sec. 206.112.
    (b) Production from leases in the Rocky Mountain Region Value your 
oil under the first applicable of the following paragraphs:
    (1) If you have an MMS-approved tendering program, the value of 
production from leases in the area the tendering program covers is the 
highest price bid for tendered volumes.
    (i) You must offer and sell at least 30 percent of your production 
from both Federal and non-Federal leases in that area under your 
tendering program.
    (ii) You also must 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.
    (iii) MMS will provide additional criteria for approval of a 
tendering program in its ``Oil and Gas Payor Handbook.''
    (2) Value is 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 must 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.
    (3) Value is 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.
    (i) Calculate the daily mean spot price by averaging the daily high 
and low prices for the month in the selected publication.
    (ii) Use only the days and corresponding spot prices for which such 
prices are published.
    (iii) You must adjust the value for applicable location and quality 
differentials, and you may adjust it for transportation costs, under 
Sec. 206.112.
    (4) If you demonstrate to MMS's satisfaction that paragraphs (b)(1) 
through (b)(3) of this section result in an unreasonable value for your 
production as a result of circumstances regarding

[[Page 73845]]

that production, the MMS Director may establish an alternative 
valuation method.
    (c) Production from leases not located in California, Alaska, or 
the Rocky Mountain Region. Value is 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
    (2) For deliveries during the production month. Calculate the daily 
mean spot price by averaging the daily high and low prices for the 
month in the selected publication. Use only the days and corresponding 
spot prices for which such prices are published. You must adjust the 
value for applicable location and quality differentials, and you may 
adjust it for transportation costs, under Sec. 206.112.
    (d) If MMS determines that any of the index prices referenced in 
paragraphs (a), (b), and (c) of this section are unavailable or no 
longer represent reasonable royalty value, in any particular case, MMS 
may establish reasonable royalty value based on other relevant matters.
    (e) What if I transport my oil to my refinery and believe that use 
of a particular index price is unreasonable?
    (1) You may apply to the MMS Director for approval to use a value 
representing the market at the refinery if:
    (i) You transport your oil directly to your or your affiliate's 
refinery, or exchange your oil for oil delivered to your or your 
affiliate's refinery; and
    (ii) You must value your oil under this section at an index price; 
and
    (iii) You believe that use of the index price is unreasonable.
    (2) You must provide adequate documentation and evidence 
demonstrating the market value at the refinery. That evidence may 
include, but is not limited to:
    (i) Costs of acquiring other crude oil at or for the refinery;
    (ii) How adjustments for quality, location, and transportation were 
factored into the price paid for other oil;
    (iii) Volumes acquired for and refined at the refinery; and
    (iv) Any other appropriate evidence or documentation that MMS 
requires.
    (3) If the MMS Director approves a value representing market value 
at the refinery, you may not take an allowance against that value under 
Sec. 206.112(b) unless it is included in the Director's approval.


Sec. 206.104  What index price publications are acceptable to MMS?

    (a) MMS periodically will publish in the Federal Register a list of 
acceptable publications based on certain criteria, including but not 
limited to:
    (1) Publications buyers and sellers frequently use;
    (2) Publications frequently mentioned in purchase or sales 
contracts;
    (3) Publications that use adequate survey techniques, including 
development of spot price estimates based on daily surveys of buyers 
and sellers of ANS and other crude oil; and
    (4) Publications independent from MMS, other lessors, and lessees.
    (b) Any publication may petition MMS to be added to the list of 
acceptable publications.
    (c) MMS will reference the tables you must use in the publications 
to determine the associated index prices.


Sec. 206.105  What records must I keep to support my calculations of 
value under this subpart?

    If you determine the value of your oil under this subpart, you must 
retain all data relevant to the determination of royalty value. You 
must be able to show how you calculated the value you reported, 
including all adjustments for location, quality, and transportation, 
and how you complied with these rules. Recordkeeping requirements are 
found at part 207 of this title. MMS may review and audit your data, 
and MMS will direct you to use a different value if it determines that 
the reported value is inconsistent with the requirements of this 
subpart.


Sec. 206.106  What are my responsibilities to place production into 
marketable condition and to market production?

    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. If you use gross proceeds under an arm's-length 
contract in determining value, you must increase those gross proceeds 
to the extent that the purchaser, or any other person, provides certain 
services that the seller normally would be responsible to perform to 
place the oil in marketable condition or to market the oil.


Sec. 206.107  How do I request a value determination?

    (a) You may request a value determination from MMS regarding any 
Federal lease oil production. Your request must:
    (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. You must inform MMS of 
any changes to relevant facts that occur before we respond to your 
request;
    (4) Include copies of all relevant documents;
    (5) Provide your analysis of the issue(s), including citations to 
all relevant precedents (including adverse precedents); and
    (6) Suggest your proposed valuation method.
    (b) MMS will reply to requests expeditiously. MMS may either:
    (1) Issue a value determination signed by the Assistant Secretary, 
Land and Minerals Management; or
    (2) Issue a value determination by MMS staff; or
    (3) Inform you in writing that MMS will not provide a value 
determination. Situations in which MMS typically will not provide any 
value determination include, but are not limited to:
    (i) Requests for guidance on hypothetical situations;
    (ii) Matters that are inherently factual in nature; and
    (iii) Matters that are the subject of pending litigation or 
administrative appeals.
    (c)(1) A value determination signed by the Assistant Secretary, 
Land and Minerals Management, is binding on both you and MMS until the 
Assistant Secretary modifies or rescinds it.
    (2) After the Assistant Secretary issues a value determination, you 
must make any adjustments in royalty payments that follow from the 
determination and, if you owe additional royalties, pay late payment 
interest under 30 CFR 218.54.
    (3) A value determination signed by the Assistant Secretary is the 
final action of the Department and is subject to judicial review under 
5 U.S.C. 701-706.
    (d)(1) A value determination issued 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.
    (2) A value determination by MMS staff is not an appealable 
decision or order under 30 CFR part 290 subpart B. If you receive an 
order requiring you to pay royalty on the same basis as the value 
determination, you may appeal that order under 30 CFR part 290 subpart 
B.
    (e) A change in applicable statute or regulation on which any value 
determination is based takes precedence

[[Page 73846]]

over the value determination, regardless of whether the MMS Director or 
the Assistant Secretary modifies or rescinds the value determination.
    (f) The MMS Director or the Assistant Secretary generally will not 
modify or rescind a value determination retroactively, 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.
    (g) MMS may make requests and replies under this section available 
to the public, subject to the confidentiality requirements under 
Sec. 206.108.


Sec. 206.108  Does MMS protect information I provide?

    Certain information you submit to MMS regarding valuation of oil, 
including transportation allowances, may be exempt from disclosure. To 
the extent applicable laws and regulations permit, MMS will keep 
confidential any data you submit that is privileged, confidential, or 
otherwise exempt from disclosure. All requests for information must be 
submitted under the Freedom of Information Act regulations of the 
Department of the Interior at 43 CFR part 2.


Sec. 206.109  When may I take a transportation allowance in determining 
value?

    (a) What transportation allowances are permitted when I value 
production based on gross proceeds? This paragraph applies when you 
value oil under Sec. 206.102 based on gross proceeds from a sale at a 
point off the lease, unit, or communitized area where the oil is 
produced, and the movement to the sales point is not gathering. MMS 
will allow a deduction for the reasonable, actual costs to transport 
oil from the lease to the point off the lease under Sec. 206.110 or 
Sec. 206.111, as applicable. If MMS takes it royalty in kind, see 
Sec. 208.8.
    (b) What transportation allowances and other adjustments apply when 
I value production based on index pricing? If you value oil using an 
index price under Sec. 206.103, MMS will allow a deduction for certain 
location/quality adjustments and certain costs associated with 
transporting oil as provided under Sec. 206.112.
    (c) Are there limits on my transportation allowance?
    (1) Except as provided in paragraph (c)(2) of this section, your 
transportation allowance may not exceed 50 percent of the value of the 
oil as determined under this subpart. You may not use transportation 
costs incurred to move a particular volume of production to reduce 
royalties owed on production for which those costs were not incurred.
    (2) You may ask MMS to approve a transportation allowance in excess 
of the limitation in paragraph (c)(1) of this section. You must 
demonstrate that the transportation costs incurred were reasonable, 
actual, and necessary. Your application for exception (using Form MMS-
4393, Request to Exceed Regulatory Allowance Limitation) must contain 
all relevant and supporting documentation necessary for MMS to make a 
determination. You may never reduce the royalty value of any production 
to zero.
    (d) Must I allocate transportation costs? You must allocate 
transportation costs among all products produced and transported as 
provided in Secs. 206.110 and 206.111. You must express transportation 
allowances for oil as dollars per barrel.
    (e) What additional payments may I be liable for? If MMS determines 
that you took an excessive transportation allowance, then you must pay 
any additional royalties due, plus interest under 30 CFR 218.54. You 
also could be entitled to a credit with interest under applicable rules 
if you understated your transportation allowance. If you take a 
deduction for transportation on Form MMS-2014 by improperly netting the 
allowance against the sales value of the oil instead of reporting the 
allowance as a separate line item, MMS may assess you an amount under 
Sec. 206.116.


Sec. 206.110  How do I determine a transportation allowance under an 
arm's-length transportation contract?

    (a) If you or your affiliate incur transportation costs under an 
arm's-length transportation contract, you may claim a transportation 
allowance for the reasonable, actual costs incurred for transporting 
oil under that contract, except as provided in paragraphs (a)(1) and 
(a)(2) of this section and subject to the limitation in 
Sec. 206.109(c). You must be able to demonstrate that your contract is 
arm's length. You do not need MMS approval before reporting a 
transportation allowance for costs incurred under an arm's-length 
contract.
    (1) If MMS determines that the contract reflects more than the 
consideration actually transferred either directly or indirectly from 
you or your affiliate to the transporter for the transportation, MMS 
may require that you calculate the transportation allowance under 
Sec. 206.111.
    (2) If MMS determines that the consideration paid under an arm's-
length transportation contract does not reflect the reasonable value of 
the transportation due to either:
    (i) Misconduct by or between the parties to the arm's-length 
contract; or
    (ii) Breach of your duty to market the oil for the mutual benefit 
of yourself and the lessor, then you must calculate the transportation 
allowance under Sec. 206.111.
    (A) MMS will not use this provision to simply substitute its 
judgment of the reasonable oil transportation costs incurred by you or 
your affiliate under an arm's-length transportation contract.
    (B) The fact that the cost you or your affiliate incur in an arm's 
length transaction is higher than other measures of transportation 
costs, such as rates paid by others in the field or area, is 
insufficient to establish breach of the duty to market unless MMS finds 
additional evidence that you or your affiliate acted unreasonably or in 
bad faith in transporting oil from the lease.
    (b)(1)(i) If your arm's-length transportation contract includes 
more than one liquid product, and the transportation costs attributable 
to each product cannot be determined from the contract, then you must 
allocate the total transportation costs to each of the liquid products 
transported.
    (ii) Your allocation must use the same proportion as the ratio of 
the volume of each product (excluding waste products with no value) to 
the volume of all liquid products (excluding waste products with no 
value).
    (iii) You may not claim an allowance for the costs of transporting 
lease production that is not royalty-bearing.
    (2) You may propose to MMS a cost allocation method on the basis of 
the values of the products transported. MMS will approve the method 
unless it is not consistent with the purposes of the regulations in 
this subpart.
    (c)(1) If your arm's-length transportation contract includes both 
gaseous and liquid products, and the transportation costs attributable 
to each product cannot be determined from the contract, then you must 
propose an allocation procedure to MMS.
    (2) You may use your proposed procedure to calculate a 
transportation allowance until MMS accepts your cost allocation.
    (3) You must submit your initial proposal, including all available 
data, within three months after the last day of the month for which you 
propose an allocation procedure.
    (d) If your payments for transportation under an arm's-length 
contract are not on a dollar-per-unit basis, you must convert whatever 
consideration is paid to a dollar-value equivalent.

[[Page 73847]]

    (e) If your arm's-length sales contract includes a provision 
reducing the contract price by a transportation factor, MMS will not 
consider the transportation factor to be a transportation allowance.
    (1) You may use the transportation factor in determining your gross 
proceeds for the sale of the product.
    (2) You must obtain MMS approval before claiming a transportation 
factor in excess of 50 percent of the base price of the product.


Sec. 206.111  How do I determine a transportation allowance under a 
non-arm's-length transportation arrangement?

    (a) If you or your affiliate have a non-arm's-length transportation 
contract or no contract, including those situations where you or your 
affiliate perform your own transportation services, calculate your 
transportation allowance based on the reasonable, actual costs provided 
in this section.
    (b) Base your transportation allowance for non-arm's-length or no-
contract situations on your or your affiliate's actual costs for 
transportation during the reporting period, including operating and 
maintenance expenses, overhead, and either:
    (1) Depreciation and a return on undepreciated capital investment 
under paragraphs (g)(1) and (h) of this section, or
    (2) A cost equal to the initial capital investment in the 
transportation system multiplied by a rate of return under paragraph 
(g)(2) of this section.
    (c) Allowable capital costs are generally those for depreciable 
fixed assets (including costs of delivery and installation of capital 
equipment) which are an integral part of the transportation system.
    (d) Allowable operating expenses include:
    (1) Operations supervision and engineering;
    (2) Operations labor;
    (3) Fuel;
    (4) Utilities;
    (5) Materials;
    (6) Ad valorem property taxes;
    (7) Rent;
    (8) Supplies; and
    (9) Any other directly allocable and attributable operating expense 
which you can document.
    (e) Allowable maintenance expenses include:
    (1) Maintenance of the transportation system;
    (2) Maintenance of equipment;
    (3) Maintenance labor; and
    (4) Other directly allocable and attributable maintenance expenses 
which you can document.
    (f) Overhead directly attributable and allocable to the operation 
and maintenance of the transportation system is an allowable expense. 
State and Federal income taxes and severance taxes and other fees, 
including royalties, are not allowable expenses.
    (g) You may use either depreciation and a return on remaining 
undepreciated capital investment or a return on depreciable capital 
investment as described in paragraph (b) of this section. After you 
have elected to use either method for a transportation system, you may 
not later elect to change to the other alternative without MMS 
approval.
    (1) To compute depreciation, you may elect to use either a 
straight-line depreciation method based on the life of equipment or on 
the life of the reserves which the transportation system services, or a 
unit-of-production method. After you make an election, you may not 
change methods without MMS approval. You may not depreciate equipment 
below a reasonable salvage value.
    (2) An arm's-length change in ownership of a transportation system 
will 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.
    (3) 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.
    (4) For transportation facilities first placed in service after 
March 1, 1988, you may use as a cost an amount equal to your initial 
capital investment in the transportation system multiplied by the rate 
of return under paragraph (h) of this section. You may not claim an 
allowance for depreciation.
    (h) The rate of return is the industrial bond yield index for 
Standard and Poor's BBB rating. Use the monthly average rate published 
in ``Standard and Poor's Bond Guide'' for the first month of the 
reporting period for which the allowance applies. Calculate the rate at 
the beginning of each subsequent transportation allowance reporting 
period.
    (i) Calculate the deduction for transportation costs based on your 
or your affiliate's cost of transporting each product through each 
individual transportation system. Where more than one liquid product is 
transported, allocate costs consistently and equitably to each of the 
liquid products transported. Your allocation must use the same 
proportion as the ratio of the volume of each liquid product (excluding 
waste products with no value) to the volume of all liquid products 
(excluding waste products with no value).
    (1) You may not take an allowance for transporting lease production 
that is not royalty-bearing.
    (2) You may propose to MMS a cost allocation method on the basis of 
the values of the products transported. MMS will approve the method if 
it is consistent with the purposes of the regulations in this subpart.
    (j)(1) Where both gaseous and liquid products are transported 
through the same transportation system, you must propose a cost 
allocation procedure to MMS.
    (2) You may use your proposed procedure to calculate a 
transportation allowance until MMS accepts your cost allocation.
    (3) You must submit your initial proposal, including all available 
data, within three months after the last day of the month for which you 
request a transportation allowance.


Sec. 206.112  What adjustments and transportation allowances apply when 
I value oil using index pricing?

    When you use index pricing to calculate the value of production 
under Sec. 206.103, you must adjust the index price for location and 
quality differentials and you may adjust it for certain transportation 
costs, as follows:
    (a) If you dispose of your production under one or more arm's-
length exchange agreements, then
    (1)(i) You must adjust the index price for location/quality 
differentials. You must determine those differentials from each of your 
arm's-length exchange agreements applicable to the exchanged oil.
    (ii) Therefore, for example, if you exchange 100 barrels of 
production from a given lease under two separate arm's-length exchange 
agreements for 60 barrels and 40 barrels respectively, separately 
determine the location/quality differential under each of those 
exchange agreements, and apply each differential to the corresponding 
index price.
    (iii) 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, total the three adjustments from 
those exchanges to

[[Page 73848]]

determine the adjustment under this paragraph (a)(1)(iii). (If one of 
the three exchanges was not at arm's length, you must request MMS 
approval under paragraph (b) of this section 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.
    (2) You may adjust the index price for actual transportation costs, 
determined under Sec. 206.110 or Sec. 206.111
    (i) From the lease to the first point where you give your oil in 
exchange; and
    (ii) From any intermediate point where you receive oil in exchange 
to another intermediate point where you give the oil in exchange again; 
and
    (iii) From the point where you receive oil in exchange and 
transport it without further exchange to a market center, or to a 
refinery that is not at a market center.
    (b) For non-arm's-length exchange agreements, you must request 
approval from MMS for any location/quality adjustment.
    (c) If you transport lease production directly to a market center 
or to an alternate disposal point (for example, your refinery), you may 
adjust the index price for your actual transportation costs, determined 
under Sec. 206.110 or Sec. 206.111.
    (d) If you adjust for location/quality or transportation costs 
under paragraph (a), (b), or (c) of this section, also adjust the index 
price for quality based on premia or penalties determined by pipeline 
quality bank specifications at intermediate commingling points or at 
the market center. Make this adjustment only if and to the extent that 
such adjustments were not already included in the location/quality 
differentials determined from your arm's-length exchange agreements.
    (e) For leases in the Rocky Mountain Region, for purposes of this 
section, the term ``market center'' means Cushing, Oklahoma, unless MMS 
specifies otherwise through a document published in the Federal 
Register.
    (f) If you cannot determine your location/quality adjustment under 
paragraph (a) or (c) of this section, you must request approval from 
MMS for any location/quality adjustment.
    (g) You may not use any transportation or quality adjustment that 
duplicates all or part of any other adjustment that you use under this 
section.


Sec. 206.113  How will MMS identify market centers?

    MMS periodically will publish in the Federal Register a list of 
market centers. MMS will monitor market activity and, if necessary, add 
to or modify the list of market centers and will publish such 
modifications in the Federal Register. MMS will consider the following 
factors and conditions in specifying market centers:
    (a) Points where MMS-approved publications publish prices useful 
for index purposes;
    (b) Markets served;
    (c) Input from industry and others knowledgeable in crude oil 
marketing and transportation;
    (d) Simplification; and
    (e) Other relevant matters.


Sec. 206.114  What are my reporting requirements under an arm's-length 
transportation contract?

    You or your affiliate must use a separate line entry on Form MMS-
2014 to notify MMS of an allowance based on transportation costs you or 
your affiliate incur. MMS may require you or your affiliate to submit 
arm's-length transportation contracts, production agreements, operating 
agreements, and related documents. Recordkeeping requirements are found 
at part 207 of this title.


Sec. 206.115  What are my reporting requirements under a non-arm's-
length transportation contract?

    (a) You or your affiliate must use a separate line entry on Form 
MMS-2014 to notify MMS of an allowance based on transportation costs 
you or your affiliate incur.
    (b) For new transportation facilities or arrangements, base your 
initial deduction on estimates of allowable oil transportation costs 
for the applicable period. Use the most recently available operations 
data for the transportation system or, if such data are not available, 
use estimates based on data for similar transportation systems.
    (c) MMS may require you or your affiliate to submit all data used 
to calculate the allowance deduction. Recordkeeping requirements are 
found at part 207 of this title.


Sec. 206.116  What interest and assessments apply if I improperly 
report a transportation allowance?

    (a) If you or your affiliate net a transportation allowance against 
the royalty value on Form MMS-2014, you will be assessed an amount up 
to 10 percent of the netted allowance, not to exceed $250 per lease 
selling arrangement per sales period.
    (b) If you or your affiliate deduct a transportation allowance on 
Form MMS-2014 that exceeds 50 percent of the value of the oil 
transported without obtaining MMS's prior approval under Sec. 206.109, 
you must pay interest on the excess allowance amount taken from the 
date that amount is taken to the date you or your affiliate file an 
exception request MMS approves.
    (c) If you or your affiliate report an erroneous or excessive 
transportation allowance resulting in an underpayment of royalties, you 
must pay the additional royalties plus interest under 30 CFR 218.54.


Sec. 206.117  What reporting adjustments must I make for transportation 
allowances?

    (a) If your or your affiliate's actual transportation allowance is 
less than the amount you claimed on Form MMS-2014 for each month during 
the allowance reporting period, you must pay additional royalties plus 
interest computed under 30 CFR 218.54 from the beginning of the 
allowance reporting period when you took the deduction to the date you 
repay the difference.
    (b) If the actual transportation allowance is greater than the 
amount you claimed on Form MMS-2014 for each month during the allowance 
form reporting period, you are entitled to a credit plus interest under 
applicable rules.


Sec. 206.118  Are costs allowed for actual or theoretical losses?

    You are allowed a deduction for oil transportation which results 
from payments (either volumetric or for value) for actual or 
theoretical losses only under an arm's-length contract. You may not 
take such a deduction under a non-arm's-length contract.


Sec. 206.119  How are royalty quantity and quality determined?

    (a) Compute royalties based on the quantity and quality of oil as 
measured at the point of settlement approved by BLM for onshore leases 
or MMS for offshore leases.
    (b) If the value of oil determined under this subpart is based upon 
a quantity or quality different from the quantity or quality at the 
point of royalty settlement approved by the BLM for onshore leases or 
MMS for offshore leases, adjust the value for those differences in 
quantity or quality.
    (c) You may not claim a deduction from the royalty volume or 
royalty value for actual or theoretical losses. Any actual loss that 
you may incur before the royalty settlement metering or measurement 
point is not subject to royalty if BLM or MMS, as appropriate, 
determines that the loss is unavoidable.

[[Page 73849]]

    (d) Except as provided in paragraph (b) of this section, royalties 
are due on 100 percent of the volume measured at the approved point of 
royalty settlement. You may not claim a reduction in that measured 
volume for actual losses beyond the approved point of royalty 
settlement or for theoretical losses that are claimed to have taken 
place either before or after the approved point of royalty settlement.


Sec. 206.120  How are operating allowances determined?

    MMS may use an operating allowance for the purpose of computing 
payment obligations when specified in the notice of sale and the lease. 
MMS will specify the allowance amount or formula in the notice of sale 
and in the lease agreement.

[FR Doc. 99-33613 Filed 12-29-99; 8:45 am]
BILLING CODE 4310-MR-P