# Establishing Oil Value for Royalty Due on Federal Leases

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URL: https://www.frixlaw.com/law-library/documents/fr%3A99-33613

## Record

- **Collection:** Federal Register
- **Document type:** Proposed Rule
- **Published:** December 30, 1999
- **Citation:** 64 FR 73820

## Text

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

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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

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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

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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

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Source: Frix Law Library, https://www.frixlaw.com/law-library/documents/fr%3A99-33613. Public record. Not legal advice.