[Federal Register Volume 65, Number 51 (Wednesday, March 15, 2000)]
[Rules and Regulations]
[Pages 14022-14096]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 00-6049]



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Part II





Department of the Interior





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Minerals Management Service



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30 CFR Part 206



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

  Federal Register / Vol. 65, No. 51 / Wednesday, March 15, 2000 / 
Rules and Regulations  

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DEPARTMENT OF THE INTERIOR

Minerals Management Service

30 CFR Part 206

RIN 1010-AC09


Establishing Oil Value for Royalty Due on Federal Leases

AGENCY: Minerals Management Service, Interior.

ACTION: Final rule.

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SUMMARY: The Minerals Management Service (MMS) is amending its 
regulations regarding valuation, for royalty purposes, of crude oil 
produced from Federal leases. MMS is changing the way that oil not sold 
under an arm's-length contract is valued; providing optional ways for 
lessees to value their crude oil production if they sell it at arm's 
length following one or more arm's-length exchanges or one or more 
transfers between affiliates; changing the way that actual 
transportation costs are calculated; changing the definition of 
``affiliate'' because of a recent judicial decision; clarifying that it 
will issue binding value determinations; and adding specific regulatory 
language regarding the issue of ``second-guessing'' a sale under an 
arm's-length contract. These amendments are intended to assure that 
royalties on Federal oil production are based on a fair value and to 
otherwise simplify and improve the rule.

EFFECTIVE DATE: This rule is effective June 1, 2000.

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 
[email protected].

SUPPLEMENTARY INFORMATION: The principal authors of this final 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, DC.

I. Background

    This final rule establishes new royalty valuation procedures for 
crude oil produced from Federal onshore and offshore leases. This rule 
does not apply to oil produced from Indian leases. It replaces 
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.
    Based on our research, we believe the main general characteristics 
of competitive markets include: (1) A large number of sellers, no one 
of whom commands a large share of the total market; (2) functional 
identity of different sellers' products; (3) a large enough number of 
buyers that sellers and buyers do not establish personal relationships 
with one another and no one buyer commands a large share of the total 
market; and (4) buyers who are well informed about the prices of 
different sellers. In fact, the Federal crude oil market today is 
dominated by large integrated producers/refiners who do command a large 
share of the total market. Further, because of the proprietary nature 
of individual contract sales of crude oil, clearly there is no sharing 
of price data at the lease, and none of the other conditions for a 
competitive domestic oil market may exist. The comments submitted 
throughout this 4-plus-year rulemaking effort did not demonstrate 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 such entities operated 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 non-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 often are above posted prices and are linked, in some form, to 
market prices, such as spot or futures prices, or represent premiums 
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 domestic crude oil market, particularly on the West 
Coast and in the Rocky Mountain Region (RMR), 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 non-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 valuation 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 is not sold at arm's 
length at or near the lease. Most oil production

[[Page 14023]]

from Federal leases 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 necessarily 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 amends 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 indicators play a significant 
role in crude oil marketing in terms of negotiating deals and prices.
    Comments received 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, the new rules establish different valuation procedures for 
three different regions: California and Alaska, the RMR, and the rest 
of the country.
    MMS is adopting large portions of the February 1998 proposal, with 
certain modifications arising from:
    (1) The outline published in the March 12, 1999 notice of reopening 
of public comment period and notice of workshops;
    (2) The supplementary proposed rule published on December 30, 1999; 
and
    (3) Our responses to public comment.

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, applicable 
both to Federal and Indian leases, 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 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 55198). 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 55198); and Washington, DC 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, DC on February 25, 
1998; Lakewood,Colorado on March 2, 1998; Bakersfield, California, on 
March 11, 1998; and Casper, Wyoming, on March 12, 1998. In April 1998, 
before MMS could fully consider comments on the revised proposal and 
publish a final rule, Congress added a rider to a Fiscal Year 1998 
emergency supplemental spending measure that barred MMS from 
implementing the rule until October 1, 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 (63 FR 
36868). MMS participated in an initial meeting with various Senators 
and oil industry representatives on July 9, 1998.
    On July 16, 1998, as a result of comments during the prior comment 
period and feedback from the July 9 meeting, MMS published a further 
supplementary proposed rule (63 FR 38355) that clarified some of the 
changes MMS intended to make when the proposed rule became final.
    On July 21, 1998, Representatives Miller (California) and Maloney 
(New York) sponsored a meeting between DOI, States, the Indian 
community, and 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.
    On July 22, 1998, MMS participated in a second meeting with U.S. 
Senators and oil industry representatives. That 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 from July 24 until July 31, 1998 (63 FR 40073), 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

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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 (64 
FR 12267), reopening the comment period through April 12, 1999 (64 FR 
17990), and announced that it would hold public workshops in Houston, 
Texas; Albuquerque, New Mexico; and Washington, DC 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.
    In a supplemental appropriations bill in May 1999, Congress 
extended the moratorium on publishing a final rule until October 1, 
1999. In the FY 2000 Department of the Interior Appropriations Act, 
Congress further extended the moratorium until March 15, 2000. On 
December 30, 1999, MMS published a further supplemental proposed 
rulemaking (64 FR 73820) that proposed changes and otherwise addressed 
comments received during the comment period that ended April 27, 1999. 
The comment period for the further supplemental proposed rule closed 
January 31, 2000. During this comment period, MMS held three public 
workshops on the new proposal: in Denver, Colorado on January 18, 2000; 
Houston, Texas on January 19, 2000; and Washington, DC on January 20, 
2000. Comments received during this latest comment period are addressed 
in this preamble.
    The February 6, 1998, proposal, as modified by the July 16, 1998, 
further supplementary proposed rule, the December 30, 1999 further 
supplementary proposed rule, and through consideration of all comments 
received during the rulemaking process, led to the rule adopted here.
    In the following discussion, we use the conventions shown in the 
following table:

------------------------------------------------------------------------
               When we say--                          We mean--
------------------------------------------------------------------------
The January 1997 proposal.................  The January 24, 1997,
                                             proposed rule.
The July 1997 proposal....................  The July 3, 1997,
                                             supplementary proposed
                                             rule.
The September 1997 notice.................  The September 22, 1997,
                                             notice reopening the public
                                             comment period.
The February 1998 proposal................  The February 6, 1998,
                                             supplementary proposed
                                             rule.
The July 1998 proposal....................  The July 16, 1998,
                                             supplementary proposed
                                             rule.
The March 1999 notice.....................  The March 12, 1999, notice
                                             of reopening of public
                                             comment and notice of
                                             workshops.
The December 1999 proposal................  The December 30, 1999,
                                             supplementary proposed
                                             rule.
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III. Responses to Public Comments on January 1997 Proposal

Summary of Proposed Rule

    The January 1997 proposal retained the concept of using gross 
proceeds as a valid measure of royalty value, but limited the 
application of gross proceeds valuation to those producers who sell 
their production at arm's length and otherwise do not purchase crude 
oil. Where oil is not disposed of at arm's length, new methods would 
apply. For sales to non-refiner affiliates, the valuation method would 
be the affiliate's arm's-length resale. Alternatively, the lessee could 
base value on NYMEX prices or, in California, ANS spot prices. For 
affiliated refiners for oil not produced in California, value would be 
based on a monthly average of daily NYMEX settle prices adjusted for 
location and quality differences. For affiliated refiners in 
California, value would be the ANS spot price less appropriate 
location/quality differentials. Differentials would be derived from 
published data and information collected by MMS. All oil subject to 
exchange agreements or crude oil calls would be valued under the non-
arm's-length and no-sales procedures.
    The January 1997 proposal also:
     Reiterated the lessee's duty to market the produced oil at 
no cost to the Federal Government consistent with implied lease 
covenants.
     Eliminated the specific language permitting lessees to 
apply for use of FERC- or State-approved tariffs for transportation 
allowances in lieu of their actual costs.
     Required the submittal of a new Form MMS-4415, Oil 
Location Differential Report, to support location and quality 
differentials when valuing oil under the index price (NYMEX and ANS) 
methods.
    MMS received more than 2,000 pages of comments on this initial 
proposed rule. The comments fell into 18 topical categories (a through 
r below). Each topic begins with a description of the issue and is 
followed by a summary of comments and MMS's response.
(a) MMS's Rationale for Proposed Rule
    Summary of Comments: Twenty-seven respondents, mostly from 
industry, commented on MMS's premises for the proposed rules. All 
except one challenged the proposed rule's rationale and concepts to one 
degree or another. Comments were lengthy, with several commenters 
making similar observations. The comments had the following themes:
     MMS does not show a need to depart from existing rules or 
disclose any material foundation for the proposed rule. Nor does MMS 
show that lease markets no longer exist or that wellhead sales don't 
represent market value. Reciprocal or other oil-purchase transactions 
do not indicate that lessees are manipulating contract prices; MMS 
offers no proof of lessee misconduct or price collusion. MMS's 
consultants were allied on one side of a vigorous debate over lease 
market pricing.
     Index prices are not comparable to transactions in the 
lease market and do not reflect the same supply and demand factors. 
There is an active and viable lease market with many arm's-length sales 
to establish value.
     The limitation on arm's-length valuation is too severe and 
unfounded. Almost all producers buy oil for reasons unconnected with 
pricing schemes (e.g., for lease use or blending purposes).
     It is still feasible to value non-arm's-length sales by 
comparison to arm's-length sales. The existing valuation rules remain 
workable; they provide adequate safeguards for cases where gross 
proceeds don't reflect total consideration.
    MMS Response: MMS's reasons for issuing new rules are given in the 
Background section of this preamble. The need for new rules arises not 
only from changes in the petroleum industry's marketing practices, but 
also from the facts that: (1) The old rules were developed on the 
premise that posted prices fairly represented market value and that 
there were competitive local markets; (2) exchange agreements and other 
oil disposal transactions have become more and more problematic to use 
as the basis of royalty value; and (3) transactions based on spot 
prices, premiums above posted prices, and other index prices dominate 
the manner in which crude oil is sold today. For all of these reasons, 
the old rules were

[[Page 14025]]

becoming less effective in determining fair value for royalty purposes. 
The new rules attempt to bring the valuation procedure in step with 
actual market practices.
    MMS does not assert that no local markets exist. Rather, due to the 
frequent lack of competitive local markets, there often are 
insufficient local arm's-length transactions to reliably determine the 
value of production not disposed of at arm's length. Also, the actual 
proceeds to the lessee often are difficult to determine due to the 
prevalence of exchange agreements or reciprocal purchases. In many 
cases, the apparent arm's-length transactions in a field or area are so 
limited as to be of no use in establishing royalty value. There is no 
need for MMS to offer proof of lessee misconduct or price collusion, 
because the rule's intent is simply to obtain fair, reasonable royalty 
values that have been difficult to obtain under the existing 
regulations.
(b) Use of Posted Prices
    Summary of Comments:
    Eighteen respondents commented on MMS's abandonment of oil postings 
as a measure of value. Proponents of posted prices, mainly industry 
commenters, maintained that oil postings were still indicative of 
market value because: (1) The majority of pricing provisions in oil 
sales contracts remain postings-related; (2) a relationship exists 
between NYMEX and posted prices; and (3) oil postings are used as a 
starting point in negotiating prices and premiums. Few commenters 
argued that MMS hadn't supported its claim that posted prices no longer 
reflect value of production at the lease. Some commenters, while still 
advocating posted prices, suggested that MMS resolve the problem by 
eliminating reference to postings in the benchmarks in its current 
regulations.
    Opponents of posted prices, primarily State and local governmental 
agencies, maintained that oil postings are not a valid measure of 
value. To support their position, they pointed to the common payment of 
bonuses, or premiums, over posted prices (sometimes called the 
``postings-plus'' market), to litigation settlements paid to make up 
for low postings, to actual sales of oil above posted prices, and to 
spot prices higher than postings.
    MMS Response: By all accounts, the domestic petroleum industry 
generally no longer relies on posted prices to set arm's-length 
contract prices unless premiums are attached. Commissioned studies 
indicate that posted prices are artificially low and are used by oil 
companies largely for accounting purposes in effecting crude oil 
exchanges between themselves.
    Continuing changes in oil market pricing further demonstrate the 
need for moving away from posted prices as a value determinant. For 
example, industry recently began to use a new pricing tool called 
Calendar MERC. It is calculated much like the ``P-plus'' price quoted 
in trade periodicals, and factors in assessments for both the prompt 
(nearest) month and the second-forward month. It is quoted as a 
differential off the New York Mercantile Exchange price. Although it is 
not clear how widely the Calendar MERC price is used at present, its 
development is further evidence of industry's move not only away from 
the direct use of posted prices in their trades, but also away from 
developing prices that build on posted prices in some fashion.
    Further, MMS auditors have found that sales prices often are pegged 
to spot or futures prices. To maintain valuation procedures based on 
posted prices would understate the true market value of oil and 
diminish royalties. Consistent with the stated purposes of the proposed 
rule, the final rule eliminates posted prices as a measure of value.
(c) Definitions (Proposed Sec. 206.101)
    Marketing Affiliate--Summary of Comments: Two commenters 
recommended MMS retain the definition of ``marketing affiliate'' until 
the numerous administrative and legal actions concerning the affiliate 
issue are resolved.
    MMS Response: MMS removed this definition because it is not used in 
the final rule. Under the 1988 rules, a ``marketing affiliate'' was 
defined as an affiliate of the lessee whose function was to acquire 
only the lessee's production and market that production. The royalty 
value of oil transferred non-arm's-length to the marketing affiliate 
then became the affiliate's gross proceeds, provided the marketing 
affiliate sold the oil at arm's length. Very few, if any, marketers met 
the strict definition of a marketing affiliate, thus making this 
provision of the 1988 rules almost inconsequential. The final rule 
adopted here does not distinguish between ``marketing affiliates,'' as 
defined in 1988, and other affiliates, because the value of oil 
transferred to any affiliate is determined by the affiliate's ultimate 
disposition of that oil (or, at the lessee's option, at an index price 
or benchmark value as discussed later). Therefore, the term ``marketing 
affiliate'' is no longer needed.
    Gross Proceeds--Summary of Comments: Two commenters recommended 
changing the word ``must,'' in reference to services that must be 
performed at no cost to the lessor, to a more neutral term, because 
``must'' implies that there never will be a situation where the costs 
of these services would be deductible. One commenter recommended that 
the definition include gross proceeds accruing to an entity affiliated 
with the lessee.
    MMS Response: MMS maintains that the lessee must place production 
in marketable condition and market the production at no cost to the 
Federal Government. Legal decisions have long held that such costs are 
not deductible from royalty value. With respect to marketing costs, 
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.)). (The lessee's duty to market is 
discussed further below.) 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.
    The final rule extends gross proceeds valuation to any oil disposed 
of under an arm's-length contract, regardless of whether the seller is 
the lessee or its affiliate. Accordingly, there is no need to include 
gross proceeds accruing to an entity affiliated with the lessee in the 
definition.
    Index Pricing--Summary of Comments: Two commenters recommended 
using more generic language in case the NYMEX or ANS index prices 
become unusable. One commenter suggested the definition specifically 
refer to the monthly average spot prices for ANS crude oil delivered in 
California.
    MMS Response: The final rule modifies the index price definition to 
include spot prices for ANS, West Texas Intermediate (WTI) at Cushing, 
Oklahoma, and other appropriate spot prices. We also included a 
provision that if MMS determines that any of the

[[Page 14026]]

index prices is unavailable or no longer represents reasonable royalty 
value, MMS may establish value based on other relevant matters. The 
final rule does not use NYMEX futures prices. For applying ANS prices 
in California and Alaska, the valuation rules specify the daily mean 
spot prices published during the production month, as explained more 
fully below. This method does use monthly spot prices for ANS crude.
    Exchange Agreement--Summary of Comments: Three commenters believed 
the definition of exchange agreement was too narrow. They recommended 
the definition be broadened to include exchanges in which the receipt 
and delivery take place at the same location, multi-party exchanges, 
transportation exchanges, net-out and other overall balancing 
agreements, and exchanges involving crude for products. On the other 
hand, one commenter believed the definition was overly broad and should 
be restricted to exchanges occurring at the lease.
    MMS Response: MMS modified the exchange agreement definition from 
that originally proposed by deleting the statement that exchange 
agreements do not include agreements whose principal purpose is 
transportation (63 FR 6116, February 6, 1998). For further 
clarification, the definition in the final rule also includes examples 
of several specific types of exchange agreements. However, in the final 
rule we removed the examples included in the December 1999 proposal of 
exchanges of produced oil for futures contracts (Exchanges for 
Physical, or EFP) and exchanges of produced oil for similar oil 
produced in different months (Time Trades). These trades or exchanges 
involve different time periods and may not reflect reliable location/
quality differentials applicable to royalty payment for a particular 
production month. We believe the definition in the final rule is 
sufficient to implement the valuation rules.
    Field--Summary of Comments: One commenter pointed out that 
``field'' has no relevance under the proposed rule and should be 
deleted.
    MMS Response: ``Field'' remains a term used in the second benchmark 
for valuing production not disposed of under an arm's-length contract 
in the RMR.
(d) Gross Proceeds Valuation (Proposed Paragraph 206.102(a))
    The January 1997 proposal retained the concept of using a lessee's 
gross proceeds to value oil sold under an arm's-length contract. 
However, there were five exceptions to this provision: (1) A sales 
contract that does not reflect the total consideration for the value of 
the oil; (2) a breach of the duty to market for the mutual benefit of 
the lessee and the lessor; (3) oil disposed of under an exchange 
agreement; (4) oil subject to a call; and (5) when a lessee or its 
affiliate purchased crude oil from a third party in the United States 
within a 2-year period preceding the production month. If any of these 
exceptions applied, value would be determined under the index pricing 
methods.
    Summary of Comments: Forty persons commented on arm's-length gross 
proceeds valuation. Most commenters (primarily industry but including 
the States of Louisiana and Wyoming) believed the exceptions were too 
restrictive. Industry argued that there are active, competitive crude 
oil markets at the wellhead. Accordingly, arm's-length sales at the 
lease properly determine value. Any application of the exceptions 
(i.e., valuation under the index price methods) would derive a 
different, likely higher, value. Many objected to the requirement to 
use the index pricing methods when oil is purchased within the 2-year 
period, indicating that most producers routinely buy oil for lease 
operations.
    Two commenters indicated that gross proceeds should not be a 
valuation factor for any production in California, because gross 
proceeds have never reflected the true value of oil in that State. They 
also recommended that if the arm's-length gross proceeds provision 
remains, it be limited to non-integrated, independent producers. 
Another commenter believed that the gross proceeds provision should be 
limited to: (1) Sales by independent producers to third parties without 
repurchase agreements, and (2) sales by independent producers to major 
oil companies without repurchase or buy/sell agreements.
    MMS Response: In response to the general theme of these comments, 
MMS modified the eligibility requirements for oil valuation under 
arm's-length transactions in the July 1997 proposal. Changes included: 
(1) The expansion of gross proceeds valuation to situations involving 
competitive crude oil calls; (2) the addition of the option to use 
gross proceeds or index pricing if the lessee exchanges its oil at 
arm's length and sells the oil received in exchange at arm's length; 
and (3) elimination of the ``two-year rule'' (i.e., the requirement to 
value oil using index prices for lessees who purchase oil within a 2-
year period).
    To address the concern about reciprocal purchasing that MMS 
previously handled in the ``two-year purchase provision,'' the July 
1997 proposal added a provision that if the buyer and seller maintained 
an overall balance, the corresponding production would be valued under 
index pricing. MMS removed the language regarding overall balances as a 
separate, specific provision in the February 1998 proposal and in the 
final rule. However, oil subject to overall balance situations will be 
subject to audit and 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 overall balancing agreements thus 
ultimately will be the lessee's total consideration or the value 
determined by the non-arm's-length methods in Sec. 206.103.
    In the final rule, there are two exceptions to gross proceeds 
valuation, both of which are contained in the existing rule: a sales 
contract that does not reflect the total consideration for the value of 
production and a breach of the lessee's duty to market for the mutual 
benefit of the lessee and the lessor. (The final rule also provides the 
lessee the option of using the index value after one or more arm's-
length exchanges, or one or more inter-affiliate transfers, even when 
the oil is then sold at arm's length, as discussed further below.) MMS 
maintains that gross proceeds under truly arm's-length sales are a 
reliable measure of market value. MMS does not believe that California 
production warrants a different valuation philosophy for arm's-length 
transactions.
(e) Valuing Oil Disposed of Under Exchange Agreements (Proposed 
Paragraph 206.102(a)(4))
    In the January 1997 proposal, MMS excluded exchange agreements from 
arm's-length transactions because such agreements may or may not 
specify prices for the oil involved. Instead, they frequently specify 
dollar amounts only for location, quality, or other differentials. 
Where exchange agreements do specify prices, those prices may be 
meaningless because the contracting parties' concern is the relative 
parity in the value of oil production traded. MMS included buy/sell 
agreements in its definition of exchange agreements.
    Summary of Comments: Thirteen respondents commented on the exchange 
agreement issue. Industry commenters generally objected to the 
inclusion of buy/sell agreements with exchange agreements, arguing 
instead that buy/sell agreements should be treated as arm's-length 
sales contracts or transportation contracts. They argued that there is 
often no real distinction between a buy/sell agreement, which is

[[Page 14027]]

treated as an exchange agreement, and a transportation agreement, which 
is not treated as an exchange agreement. They argued that this is 
particularly so in California where companies owning proprietary 
pipelines require independent producers to enter into a transportation 
agreement that looks exactly like a buy/sell agreement.
    With regard to exchanges in general, State and local government 
agencies supported MMS's proposed exclusion of exchange agreements from 
arm's-length valuation, but recommended broadening the definition of 
exchange agreement (discussed above). Several industry commenters 
recommended valuing oil transferred under exchange agreements by 
reference to comparable sales.
    MMS Response: Buy/sell agreements are vulnerable to the same flaws 
as other exchange agreements in which the exchange terms involve only 
relative differentials rather than stated unit prices. Work done by the 
MMS-sponsored Interagency Task Force investigating California oil 
undervaluation, advice from several consultants, and ongoing work by 
MMS auditors, led MMS to its conclusion that exchange agreements, 
including buy/sells, may not be reliable as value indicators. However, 
in the July 1997 proposal, MMS modified the valuation procedures for 
oil involved in exchanges. This modification permitted a choice of 
using either the gross proceeds from the sale of the acquired oil 
(provided the acquired oil is sold at arm's length) or an index price 
to value the exchanged oil. This option applied only to single 
exchanges before the arm's-length sale of the acquired oil. As 
discussed below in Section VI at (b), in the February 1998 proposal, 
MMS extended the concept of applying the gross proceeds after a single 
exchange to multiple exchanges, but without the option to use an index 
price. The final rule offers the option of using the arm's-length gross 
proceeds after one or multiple arm's-length exchanges, or applying the 
index price or benchmarks appropriate to the region where the 
production occurs.
    MMS is not relying on a comparable sales approach, except in 
limited circumstances in the RMR as discussed below, primarily because 
of the lack of transparent markets at the lease.
(f) Crude Oil Calls (Proposed Paragraphs 206.102(a)(4) and (c)(2))
    Under the January 1997 proposal, MMS did not recognize oil disposed 
of under a crude oil call as sold at arm's length, regardless of 
whether the buyer and seller are affiliated; such oil would be valued 
under proposed 30 CFR 206.102(c), using the index price method.
    Summary of Comments: Twelve respondents commented on crude oil 
calls. Most commenters believed that the proposed rule was too 
restrictive, claiming that crude oil call agreements usually include 
the best price and therefore should be considered arm's-length. 
Commenters indicated that when calls are not exercised, the oil is sold 
at arm's length anyway. Two State respondents suggested that oil 
subject to crude oil calls should be valued as non arm's length only 
when the call is actually exercised.
    MMS Response: MMS recognized in the July 1997 proposal that not all 
crude oil calls are exercised and that some calls are subject to 
competitive bid. In the February 1998 proposal, MMS modified the rules 
regarding competitive crude oil calls to accept arm's-length gross 
proceeds as value in these situations. In the final rule, MMS removed 
the language regarding noncompetitive crude oil calls as a separate, 
specific provision. However, oil subject to a noncompetitive crude oil 
call will 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 will 
be the lessee's total consideration or the value determined by the non-
arm's-length methods in Sec. 206.103.
(g) NYMEX Pricing (Proposed Paragraph 206.102(c)(2)(i))
    For oil produced outside California and Alaska and not sold by the 
lessee or its affiliate under an arm's-length contract, MMS proposed in 
January 1997 that value be determined as the average of the daily NYMEX 
futures settle prices for WTI crude oil at Cushing, Oklahoma, for the 
prompt month (the month following the month of production). MMS 
proposed NYMEX prices because they were perceived to best reflect the 
current domestic crude oil market value on any given day, and there is 
minimal likelihood that any one party could influence them. To 
establish royalty value, the NYMEX prices would be reduced by location 
and quality differentials. (See also Form MMS-4415 at m below.)
    Summary of Comments: A total of 54 respondents commented on the 
NYMEX pricing proposal. Industry commenters unanimously opposed the 
idea, whereas States and other governmental agencies were divided, with 
some supporting the proposal and others opposing it. Opposing comments 
generally revolved around the asserted difference between the NYMEX 
market and the lease market. Comments included:
     NYMEX is a futures market that bears little relation to 
the market at the lease. Lease prices are driven by local supply and 
demand factors, not by NYMEX pricing; the NYMEX market is not 
synchronized with lease-market factors. NYMEX is not influenced by 
factors present at the lease, such as operational and transportation 
costs; the ease of oil futures trading gives the oil more value than it 
has at the lease.
     NYMEX prices are speculative and artificial. Those 
purchasing oil futures in the NYMEX market buy a right to obtain 
certain types of oil in the future at specified prices; NYMEX does not 
represent current sales. NYMEX is used to hedge against financial 
risks; only 30 percent of participants are industry, and 70 percent are 
speculators. Trade volumes are 10 to 20 times actual U.S. production, 
but only 3.1 percent of trades are carried out. NYMEX is mainly a paper 
market. Profits are made in successfully guessing the optimal timing of 
trades. Prices can be distorted by changing perceptions of risk, 
activities of speculators, and world events, such as wars and natural 
catastrophes. The settlement price is computed from transactions that 
occur only in the last few minutes of each day's trading.
     NYMEX-based valuation is contrary to the royalty 
provisions of the leasing statutes and lease terms, which require 
valuation at the lease at the time of production; NYMEX pricing does 
not provide contemporaneous valuation because the prompt month does not 
coincide with the production month.
     NYMEX does not represent the crude oil market in the RMR, 
which is driven by refinery-product prices, not the NYMEX.
    One commenter suggested using adjusted spot prices instead of the 
NYMEX method to value production, particularly for the Gulf of Mexico.
    Proponents of NYMEX pricing believed it is a valid measure of the 
market value of crude oil. Reasons included (1) the large volume of oil 
traded; (2) invulnerability to manipulation or control (however, a few 
of the opponents of NYMEX pricing indicated that the NYMEX market is 
indeed vulnerable to manipulation); and (3) the opportunity for 
arbitrage to mediate the differences between the values of paper 
barrels and actual barrels of oil.
    MMS Response: The final rule does not use NYMEX as a measure of 
value. However, the body of evidence regarding actual marketing 
practices indicates that index prices play a significant role in 
setting contract

[[Page 14028]]

prices. In considering the numerous comments, MMS dropped its NYMEX 
pricing approach in the February 1998 proposal except for the third 
benchmark in valuation of crude oil produced in the newly-defined RMR 
and not disposed of at arm's length. In the final rule, MMS also 
dropped NYMEX as a valuation basis in the RMR.
    For leases outside California, Alaska, and the RMR, in February 
1998 MMS proposed to use spot, rather than NYMEX, prices to value oil 
not disposed of at arm's length. We made this change because spot 
prices nearly duplicate NYMEX prices when NYMEX prices are properly 
adjusted for location and quality differentials. Moving to spot prices 
at the market center thus saves one step in the adjustment of NYMEX 
prices back to the lease, namely the adjustment between Cushing, 
Oklahoma, and the market center. Spot prices are valid indicators of 
market value because they and similar prices play a significant role in 
sales contracts and they are readily available to lessees via 
commercial price reporting services.
    For the RMR, the final rule uses the WTI spot price at Cushing, 
Oklahoma, adjusted for location and quality, as the third valuation 
benchmark for oil not disposed of at arm's length. We believe that this 
valuation mechanism is appropriate for the RMR because the only 
published spot price for this region at this point in time--at 
Guernsey, Wyoming--is derived from a survey of the few trades occurring 
at that location. The price, therefore, is not a reliable measure of 
value.
(h) ANS Spot Prices (Proposed Paragraph 206.102(c)(2)(ii))
    For oil produced in California and Alaska and not sold by the 
lessee or its affiliate under an arm's-length contract, MMS proposed, 
in January 1997, that value be the average of the daily mean ANS spot 
prices for the month of production published in an MMS-approved 
publication. MMS chose ANS spot prices because they represent large 
volumes of oil delivered into the California market and used as 
refinery feedstock. In contrast, the other spot prices published for 
local California crude oil (including, for example, Kern River and Line 
63), like those published for Guernsey, Wyoming, do not involve large 
enough volumes to justify their use for royalty valuation. To establish 
royalty value, the ANS spot prices would be adjusted for location and 
quality differentials.
    Summary of Comments: Fifteen industry commenters opposed the ANS 
pricing proposal, while two California governmental agencies supported 
it. Opposing arguments included:
     The reported ANS spot prices are unreliable because 
transaction volumes are small; only 10 percent of ANS production is 
sold on the spot market, all of it by only one company.
     The ANS price quotes are indicative of the value of ANS 
crude delivered in waterborne cargo volumes and not of the value of 
California crude oils delivered by pipeline.
     The method used by the trade press to determine spot 
prices is unclear, and many of the transactions reported to the trade 
press involve buy/sell exchanges which MMS believes to be unreliable.
     The quality of ANS crude is very different from California 
crude. ANS crude is relatively light compared to crude oil produced in 
California. Much of California crude is heavy and contains heavy metals 
and other impurities that cause refining difficulties. Accordingly, 
California crude prices are discounted relative to ANS crude.
    In summary, industry believed that the ANS method would not reflect 
the value of California crude oil. A few commenters asserted that the 
calculated values would be much higher than those realized in actual 
sales or through local spot prices.
    California governmental agencies (the State and one municipality) 
endorsed the ANS method. They stated that ANS crude directly competes 
with California crude as refinery feedstock--often accounting for more 
than one-third of the oil refined in California--and thus should form 
the basis for a competitive price for California crude. In support of 
this, one commenter indicated that the major California oil companies 
evaluated the actual value of California crudes by comparing them to 
the ANS spot prices; this commenter concluded that the major oil 
companies viewed the ANS price as the market value of California 
crudes. The other commenter was concerned that the published ANS prices 
might become unavailable or fail to yield a reasonable value. This 
commenter recommended a safety net for ANS pricing at no less than 20 
percent below the NYMEX price to guard against these situations.
    MMS Response: 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.
(i) Duty to Market (Proposed Paragraph 206.102(e)(1))
    The January 1997 proposal restated the lessee's duty to market the 
oil for the mutual benefit of the lessee and lessor at no cost to the 
Federal Government, consistent with longstanding Departmental practice 
and implied lease covenants.
    Summary of Comments: Nineteen respondents, all representing 
industry, commented on the duty-to-market provision. They all opposed 
the provision on the following grounds:
     Downstream marketing costs enhance the value of the oil. 
MMS is not entitled to claim royalties on the value added by those 
expenses and risks incidental to downstream activities, particularly 
when value is determined at a marketing center downstream of the lease.
     The lessor does not share mutually in the risks inherent 
in downstream marketing activities; accordingly, there is no mutual 
benefit when one party bears all the costs and risks.
     There is no legal foundation supporting a no-cost duty to 
market when the point of royalty determination

[[Page 14029]]

is moved to a downstream market center.
     Placing production in marketable condition (physically 
conditioning the production for market) is separate from a duty to 
market; lease terms do not require the lessee to market the production 
at no cost to the lessor.
    MMS Response: It is a well-established principle of oil and gas law 
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 obliged 
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), section 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 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 at the 
highest price obtainable 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 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, 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 
C.F.R. 206.150(e) * * * and processing allowances for processed gas 
authorized by 30 C.F.R. 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, especially in light of the gross proceeds minimum value 
requirement. The only deductible costs are transportation costs and, in 
the case of ``wet'' gas with heavier entrained liquid hydrocarbons, 
processing costs.
    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 
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 in the 
proposed and final rules 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 the transportation allowances (or 
location differentials) 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) (1988-1997). 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 illustrative 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

[[Page 14030]]

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 
production 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).
    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 adopts the reasoning of that decision in response to the 
commenters' argument.
(j) Differentials (Proposed Paragraph 206.105(c))
    When value is based on index pricing, certain location and quality 
differentials are required to adjust the value of the oil at the index 
pricing point to obtain royalty value of the oil produced from the 
lease. The January 1997 proposal applied location and quality 
differentials to adjust the value between (1) the index pricing point 
and the appropriate market center and (2) the market center and the 
aggregation point. The first differential was the difference between 
the average spot prices for the respective crude oils at the index 
pricing point and at the market center. The second differential was 
either an express differential under an arm's-length exchange agreement 
relative to the market center/aggregation point pair or a differential 
calculated and published by MMS for the market center/aggregation point 
pair. MMS would have determined the latter differential from 
information reported on Form MMS-4415.
    The location differentials reflect the relative differences in the 
value of crude oil delivered at different locations; they are not 
transportation cost allowances. Under the January 1997 proposal, the 
lessee would use transportation allowances to adjust the value of the 
crude oil from the aggregation point (or market center) to the lease. 
Comments on transportation allowances are addressed elsewhere in this 
preamble.
    Summary of Comments: Thirty-one respondents commented on 
differentials. Comments generally fell into two categories:
    (1) The differentials would be 1 year out of date and would not 
reflect market conditions at the time of production. They particularly 
ignore the dynamic supply and demand processes that operate on daily 
and seasonal bases.
    (2) The differentials would not adequately adjust for quality 
differences between the lease and the index pricing point because of 
commingling. There is no gravity adjustment between the lease and the 
aggregation point.
    In sum, many commenters believed that the differentials would not 
capture the value of oil produced at the lease. Other comments 
included:
     Differentials do not recognize all transportation costs or 
value added from blending, aggregation, storage, and other marketing 
services.
     Aggregation points with limited transactions will give 
statistically invalid differentials.
     Exchange agreements may not provide all the needed data or 
specify which lease(s) the oil came from.
     Differentials might be calculated from inaccurate and 
unreliable data, particularly with regard to selecting ``alternative 
disposal points.''
     Gathering is not adequately addressed in the calculation 
of differentials.
     Spot prices represent marginal barrels (small volume) to 
make up for refinery needs; they do not reflect the price differences 
between the market centers and index pricing points.
     For California, a comparison of ANS spot prices and field 
spot prices captures more than the price difference attributable to 
location. Furthermore, where spot prices are reported for a field 
rather than an aggregation point, and the exchange reflects a transfer 
at the lease or field, the differential would permit a lessee to 
recover the cost of transporting to an ``aggregation point'' twice.
    MMS Response: In the final rule, in response to the various 
comments, MMS modified the previous proposals governing differentials 
by:
    (1) Eliminating MMS-published differentials because MMS believes 
that lessees that would be subject to index pricing generally will have 
sufficient information to accurately determine location/quality 
differentials, with relatively rare exceptions. As a result of 
eliminating MMS-published differentials, the proposed Form MMS-4415 is 
not part of the final rule.

[[Page 14031]]

Because MMS is not requiring the proposed form, it is not necessary to 
address the extensive comments MMS received regarding the content and 
timing of the form.
    (2) Eliminating the location differential between the index pricing 
point and the market center because using spot market prices has made 
the index pricing point and market center the same.
    (3) Recognizing separate quality adjustments to reflect the 
differences between the oil produced from the lease and the oil at the 
market center or refinery or other alternate disposal point, or between 
intermediate exchange points. Those quality adjustments specified in 
exchange agreements will automatically account for those differences in 
quality.
    Other appropriate quality adjustments would be based on pipeline 
quality bank specifications and related premia and penalties. MMS 
believes these changes will permit determination of reasonable and 
proper differentials.
(k) Requiring Use of Actual Transportation Costs (Amended Paragraphs 
206.105 (b) and (g))
    Aside from new rules at proposed paragraph 206.105(c) addressing 
differentials and transportation allowances under the proposed index 
pricing methodology, MMS's other change to the transportation allowance 
rules in the January 1997 proposal was the proposed deletion of 
existing paragraph 206.105(b)(5). That paragraph allows those lessees 
with non-arm's-length or no transportation agreements to apply for an 
exception from the requirement to compute their actual transportation 
costs and instead use a FERC- or State-approved tariff. Deleting this 
paragraph would remove the exception and require lessees to use actual 
transportation costs in all cases.
    MMS also proposed to amend existing paragraph 206.105(f) (proposed 
to be redesignated as paragraph 206.105(g)), which disallows deductions 
for actual or theoretical losses. MMS made this change to be consistent 
with the deletion of paragraph 206.105(b)(5). In the final rule, the 
language addressing actual or theoretical losses appears at new 
Sec. 206.118.
    Summary of Comments: Sixteen respondents commented on the proposed 
change. Three commenters supported removing the exception, stating that 
actual costs better reflect a netted back value and that tariffs are 
not reviewed to determine their reasonableness.
    The remaining commenters contended that FERC tariffs remain a 
viable measure of transportation costs in non-arm's-length movements. 
They argued that it is discriminatory to treat affiliated producers, 
who would have to use their transporting affiliate's actual costs, 
differently from non-affiliated producers, who may pay a FERC tariff as 
their arm's-length transportation cost. They particularly asserted that 
line losses should be an allowable cost to be comparable with costs 
included in FERC tariffs.
    MMS Response: MMS has deleted this provision in the final rule 
because it continues to believe that doing so results in allowances 
better reflecting lessees' actual transportation costs. There is no 
discrimination between producers with transportation affiliates who 
must use their calculated actual transportation costs and non-
affiliates who may apply a FERC tariff as their arm's-length 
transportation cost. In both instances the parties would be deducting 
their actual, reasonable transportation costs. Consistent with this 
concept, the final rule permits a deduction for oil transportation 
resulting from payments (either volumetric or for value) for actual or 
theoretical losses only under an arm's-length contract.
(l) Transportation Cost Allowances for California and Alaska (Proposed 
Paragraph 206.105(c)(3)(ii))
    As initially proposed in January 1997, the determination of 
differentials and transportation allowances depends on whether the oil 
is (1) disposed of under an arm's-length exchange agreement with an 
express location differential; (2) moved directly to an alternate 
disposal point, such as a refinery; or (3) moved directly to a market 
center. For oil moved directly to an alternate disposal point, proposed 
paragraph 206.105(c)(3)(ii), and, similarly, proposed paragraph 
206.105(c)(2)(ii), permitted deduction of a transportation allowance 
based on the actual costs of transporting the oil between the lease and 
the alternate disposal point. In addition, this section permitted 
deduction of a location differential, calculated as the difference 
between the average published spot price at the aggregation point 
nearest the lease and the spot prices for ANS crude at the associated 
market center/index pricing point.
    Summary of Comments: Two commenters noted that this provision may 
allow for substantial ``double dipping'' of transportation cost 
deductions. They indicated that spot prices reflect in part the cost of 
moving the crude from the aggregation point to the market center. If 
transportation to the alternate disposal point bypasses an aggregation 
point, the lessee is allowed to deduct its actual transportation costs 
plus a location differential, which, having been computed from spot 
prices, has imbedded transportation costs. The transportation allowance 
thus will double the deduction for the location differential between 
the lease and the market center.
    They also asserted that the proposed rule did not restrict the 
location of the alternate disposal point relative to the lease, meaning 
that crude could be shipped cross country and have a substantial 
transportation deduction. They recommended that MMS limit the maximum 
transportation cost deduction to no more than the cost of moving the 
crude by pipeline from the lease to the nearest market center.
    MMS Response: Sections 206.105(c)(2)(ii) and (c)(3)(ii) of the 
January 1997 proposal were modified and reproposed as Secs. 206.112 and 
206.113 in the February 1998 proposal, which are now adopted as 
Sec. 206.112 in the final rule with changes discussed below. In the 
final rule, if a lessee or its affiliate transports lease production 
directly to an alternate disposal point, it may adjust the index price 
for the actual costs of transportation under Sec. 206.110 or 
Sec. 206.111. The lessee must also adjust the index price for quality 
based on premia or penalties determined by pipeline quality bank 
specifications. This will not result in the ``double-dipping'' with 
which the commenter was concerned. The final rule also includes a 
provision at Sec. 206.112(g) that prohibits a lessee from using any 
transportation or quality adjustment that duplicates all or part of any 
other adjustment, thus eliminating any possibility of double deduction 
for the location differential between the lease and the alternate 
disposal point or market center. MMS believes that as a practical 
matter, alternate disposal points will be reasonable distances from the 
lease and that no cost limits (beyond the 50 percent limit contained in 
this final rule at Sec. 206.109(c)) are necessary.
(m) Form MMS-4415 (Proposed Paragraph 206.105(d)(3))
    Under the January 1997 proposal, all lessees and their affiliates 
annually would have to submit proposed Form MMS-4415, Oil Location 
Differential Report, to enable MMS to calculate location and quality 
differentials under the index pricing methods. As originally proposed, 
information would be collected for all leases--Federal, State, private, 
and Indian. MMS would use the reported data to calculate and publish

[[Page 14032]]

acceptable differentials between market centers and aggregation points.
    Summary of Comments: Twenty-eight respondents commented on the 
proposed form. Most comments were negative and revolved around the 
added cost and administrative burden of preparing the reports; many 
comments questioned the accuracy of the calculated differentials. 
Comments included:
     Data collection is time consuming, burdensome, and costly.
     The reporting requirement violates the Paperwork Reduction 
Act.
     MMS's cost and time estimates are inadequate. They do not 
reflect the actual time needed to acquire the data and complete the 
report; nor do they reflect the costs of systems or accounting changes 
needed to comply with the reporting requirement.
     Annual differentials do not reflect daily or seasonal 
market changes (i.e., current market conditions); therefore, the 
differentials will be inaccurate and constantly out of date.
     Multiple crude oil grades exchanged at a given aggregation 
point, and other factors, mask the true value in exchange agreements.
     Transporting crude oil from the lease to a market center 
may involve multiple transportation segments and exchanges, thus 
compounding the data collection and reporting burden.
     MMS does not have the authority to collect information on 
non-Federal leases.
     Instructions are ambiguous or incomplete; for example, who 
completes the form when the payor is not the lessee, what 12-month 
period is used, and when is a report required when different exchange 
agreements apply to a lease in different months?
     The method of calculating the differentials is not clear, 
and industry will not be able to verify results because the information 
is proprietary.
     The information does not reflect exchanges that occur at 
the wellhead.
     The information may be duplicative and misrepresentative, 
such as when two payors report the same exchange.
     Determining what contracts contain crude oil calls might 
require considerable research, since reporting parties may not know 
when a call provision has been exercised.
    One State recommended that instead of requiring Form MMS-4415 to 
calculate a transportation differential, MMS should publish a rate 
based on the lowest FERC tariff for which a significant amount of crude 
oil moves from the aggregation point to the market center. This State 
also recommended that information collection be limited to exchanges at 
the lease and market center, thus eliminating the need to calculate 
differentials to and from the aggregation point.
    MMS Response: In the final rule, MMS will not publish location/
quality differentials because MMS believes that lessees generally will 
have sufficient information to accurately determine them, 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. As a result of 
eliminating MMS-published differentials, the proposed Form MMS-4415 is 
not part of the final rule. Because MMS is not requiring the proposed 
form, it is not necessary to address the extensive comments MMS 
received regarding the content and timing of the form.
    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 will have the necessary information regarding actual 
transportation costs to claim the appropriate transportation allowance.
(n) Sale of Federal Royalty Oil (Proposed Paragraph 208.4(b)(2))
    In the January 1997 proposal, MMS proposed to tie the royalty-in-
kind (RIK) valuation to the index pricing provisions of 30 CFR 
206.102(c)(2). MMS believed this change would provide certainty in 
pricing for buyers and simplify reporting for producers.
    Summary of Comments: Aside from the numerous commenters that 
recommended MMS take all its royalty in kind and market it, five 
respondents provided comments relevant to the proposed regulatory 
change. Comments included:
     The rules should allow RIK refiners to opt in and out of 
contracts without terminating the contracts.
     Index pricing does not provide an incentive to RIK 
refiners because they can buy cheaper crude under long-term contracts. 
Arm's-length prices should be used for royalty value.
     RIK refiners need assurance they will not be liable for 
retroactive price provisions, and that the price invoiced is final and 
not subject to later revision; producers should be liable for any 
adjustments.
     RIK refiners should be billed for actual volumes 
delivered, not produced; MMS should penalize the producer for not 
delivering the RIK volume.
     RIK refiners should receive value and volume information 
at the same time as MMS.
    One commenter recommended scrapping the RIK program because it is 
too difficult and costly to administer.
    MMS Response: In the February 1998 proposal, MMS decided not to 
proceed with the proposal to modify the RIK valuation procedures. 
Instead, MMS decided to establish future RIK pricing terms directly 
within the RIK contracts. Therefore, this issue is not part of this 
rulemaking.
(o) Added Administrative and Economic Burdens
    Summary of Comments: Twenty-five commenters thought the proposed 
rules would create a considerable administrative burden and add 
additional costs for both industry and MMS. Many comments were on the 
preparation of Form MMS-4415. They indicated that acquiring and 
compiling the needed information would take much longer than MMS's 
estimate of 15 minutes. (One commenter estimated 2 hours per form.) 
Other comments indicated there would be additional costs due to new 
accounting systems, new software, and additional personnel needed to 
administer the new rules, both for industry and MMS. A few commenters 
speculated that the added costs to producers, particularly small 
producers, might force abandonment of marginal wells or investment in 
other areas.
    MMS Response: As discussed previously, MMS eliminated Form MMS-4415 
in the final rule. We discuss other administrative costs in Section XI 
of this preamble.
(p) Fairness, Procedural Conduct, and Workability
    Summary of Comments: Thirty-three industry respondents opposed as 
inequitable the valuation methods of the January 1997 proposal for oil 
not sold at arm's length. Their comments revolved around the index 
pricing method and had the following themes:
     The leasing acts and lease terms require valuation at the 
lease. MMS exceeds its statutory authority by implementing a valuation 
method away from the lease without recognizing all the downstream 
value-added costs and risks (such as marketing costs) as deductions. 
This overstates the value of production at the lease and creates 
``phantom income'' to which MMS is not entitled. (Some commenters 
believed the index pricing method was tantamount to price fixing.)
     The proposed rule has dual standards. It discriminates 
between

[[Page 14033]]

similarly-situated lessees by requiring the integrated lessee to base 
value on a different methodology. It disqualifies many producers from 
using their gross proceeds as value when they engage in exchanges or 
oil purchases.
     The proposed rule is contrary to the deepwater royalty 
reduction program.
     The index-pricing method might force RIK refiners into 
paying higher prices.
    Some commenters believed that MMS failed to articulate a factual 
basis for its conclusion that arm's-length transaction prices are no 
longer valid indicators of value. They also argued that MMS had not 
provided sufficient time for industry to analyze and comment on the 
proposed rule and claimed that MMS had not complied with the Unfunded 
Mandates Reform Act, the Paperwork Reduction Act, Executive Order 
12630, or Executive Order 12866. Some commenters believed that the 
proposed rule is extremely complex and difficult to implement.
    MMS Response: As indicated in the Background section of this 
preamble, the reason for this rulemaking is to assure that royalties 
are based on market values. The modifications adopted in this final 
rule strengthen the market value concept for royalty valuation.
    The final rule maintains the concept of using a lessee's gross 
proceeds to value production sold at arm's-length. However, most 
Federal oil is disposed of under other than arm's-length conditions. 
Different standards historically have existed for dispositions not at 
arm's length, because such transactions are not reliable indicators of 
what parties will do in a competitive market. Contract prices between 
affiliated entities may be influenced by many factors other than market 
forces.
    MMS also notes that the governing statutes and lease terms give the 
Secretary the authority to establish royalty value. The Mineral Leasing 
Act of 1920 (MLA), as amended numerous times, authorizes the Secretary 
to prescribe necessary and proper rules and regulations to carry out 
the purposes of the MLA. The Outer Continental Shelf Lands Act of 1953 
(OCSLA), as amended, requires the Secretary to administer the 
provisions of the OCSLA relating to the leasing of the OCS, and 
authorizes the Secretary to prescribe such rules and regulations as may 
be necessary to carry out such provisions. Further, the Federal Oil and 
Gas Royalty Management Act of 1982 (FOGRMA) reemphasized the 
Secretary's royalty management authorities and responsibilities for 
Federal, OCS, and Indian oil and gas leases. Section 301(a) of FOGRMA, 
30 U.S.C. 1751(a), says ``The Secretary shall prescribe such rules and 
regulations as he deems reasonably necessary to carry out this Act.''
    Also, the royalty clauses of Federal oil and gas leases say that 
the Secretary of the Interior may establish reasonable minimum royalty 
values (considering highest prices paid for part or a majority of like-
quality production in the same field, prices received by the lessee, 
posted prices, and other relevant matters, and, whenever appropriate, 
after notice and opportunity to be heard). Thus, MMS believes this 
rulemaking effort complies with both the letter and spirit of the 
statutes and lease terms.
    MMS addressed the Unfunded Mandates Reform Act, the Paperwork 
Reduction Act, Executive Order 12630, and Executive Order 12866 in the 
February 1998 proposal and does so again in Section XI of this 
preamble.
(q) Interim Final Rule
    MMS indicated that it might publish an Interim Final Rule while it 
evaluated the methodology in the proposed rule. This approach would 
provide the flexibility to do a revision after the first year without a 
new rulemaking.
    Summary of Comments: Twenty respondents commented on this approach. 
All commenters opposed the issuance of an Interim Final Rule, 
indicating that such a rule would be overly costly and burdensome to 
both industry and MMS, especially if MMS later changed the valuation 
standards.
    MMS Response: MMS has abandoned the notion of an Interim Final Rule 
for this rulemaking and is publishing a Final Rule instead.
(r) Alternatives
    Summary of Comments: Fifty commenters suggested one or more 
alternatives to the proposed rules. The leading alternative by far was 
the recommendation that MMS take and market its royalty share in kind. 
Other alternatives revolved around modifying the existing non-arm's-
length valuation benchmarks.
    Almost all industry commenters and some State commenters 
recommended that MMS expand its current RIK program. Two industry trade 
organizations indicated that MMS would benefit from an RIK program thus 
ending valuation controversies. MMS would further benefit by earning 
the higher rewards that the market holds for successful risk-takers. 
Several commenters recommended that MMS model its RIK program after 
that of Alberta, Canada. One State suggested using RIK sales to 
determine marketing/location differentials and to obtain comparable 
sales information to value oil not disposed of at arm's length. 
Commenters generally believed that an RIK program would be less 
burdensome on industry, would reduce MMS's administrative costs, and 
would ensure proper valuation. Some suggested that MMS auction the RIK 
oil at the lease to gain the best price.
    Several commenters suggested revising the existing non-arm's-length 
valuation benchmarks to eliminate reliance on posted prices but still 
maintain benchmarks. Besides deleting references to posted prices, 
suggestions included arranging the benchmarks as follows:
     Prices received by the lessee under other comparable 
arm's-length transactions in the same field or area, including prices 
bid in response to tendering programs.
     Arm's-length prices received by others in the field.
     Prices from nearby fields within an area acceptable to 
MMS.
     Prices received by MMS, adjusted to the lease, from its 
sales of RIK oil from the field.
     A netback method, perhaps based on index prices, adjusted 
back to the lease.
    One industry commenter suggested using the average of posted prices 
to establish the benchmark value. One State commenter indicated that 
netting back is the only valid indicator of market value for integrated 
companies.
    MMS Response: MMS does not believe that taking all Federal oil in 
kind is in the best interests of the American public or that such a 
program would enhance royalties. MMS already has the authority under 
existing law and lease agreements to take royalty in kind when it would 
be beneficial to the taxpayer. We believe it would be a mistake to 
require all Federal oil to be taken in kind. For example, the taking of 
de minimus production in remote areas could lead to substantial revenue 
losses. MMS intends to continue its existing royalty-in-kind programs 
to determine where and how it can most effectively use its authority to 
take royalties in kind. This will result in the best overall return to 
the American public.
    Several of the suggested revisions to the non-arm's-length 
valuation benchmarks revolve around finding comparable sales 
transactions. But commenters have not demonstrated the consistent 
existence or availability of such transactions for volumes sufficient 
to use for royalty valuation. To the contrary, MMS believes that 
nationwide about two-thirds of crude oil production

[[Page 14034]]

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. The RMR, where reliable spot prices are not readily 
available, is an exception--about two-thirds of crude oil produced 
there is sold at arm's length. In addition, this proposal has 
substantial practical difficulties since companies are not privy to 
comparable sales transactions and such information available to MMS is 
unaudited for current periods. The final rule thus primarily uses index 
prices, adjusted for location and quality, to establish value for oil 
not sold at arm's length. As indicated above, MMS has concluded that 
posted prices no longer reflect market value, so any scheme using 
posted prices would not accomplish the goal of this rulemaking.
    General Comment--MMS Consultants. Aside from the topical categories 
discussed above, we received several comments throughout the rulemaking 
process that MMS relied too heavily on reports by consultants with 
predisposed positions. However, in developing this rule, MMS sought out 
the best experts available to advise it on the petroleum market. These 
experts provided MMS with valuable information on current and past 
marketing practices. Further, analyses of the industry consultants' 
comments by MMS's consultants (Review of Selected Technical Reports on 
MMS's Proposed Federal Oil Rule and Supplemental Rule, Innovation & 
Information Consultants, Inc., September 25, 1997) suggest that many 
arguments have multiple perspectives and are equivocal. MMS appreciates 
these different viewpoints and considered them in deliberating on this 
rulemaking.

IV. Responses to Public Comments on July 1997 Proposal

Summary of Proposed Rule

    The primary purpose of the July 1997 proposal was to revise the 
eligibility requirements for oil valuation under arm's-length 
transactions. (See (b) below.) Specifically, the supplementary 
proposal:
     Expanded gross proceeds valuation to dispositions 
involving competitive crude oil calls,
     Extended index pricing valuation to ``overall balance'' 
situations,
     Deleted the requirement to value oil using index prices 
for lessees who purchased oil in the last 2 years, and
     Added language to value oil subject to a single exchange 
agreement under either the arm's-length gross proceeds accruing after 
the exchange or the index pricing method.
    MMS also asked for further comments on collecting information on 
proposed Form MMS-4415 and reopened the comment period on the January 
1997 proposal.
    We received over 270 pages of written comments from 27 entities, 
including independent oil and gas producers, major oil and gas 
companies, petroleum industry trade associations, States, a 
municipality, consultants, and futures market representatives. Comments 
fell into 11 topical categories ((a) through (k) below). Many of the 
respondents reiterated or expanded on the same comments made on the 
January 1997 proposal.
(a) Posted Prices
    Summary of Comments: Two respondents submitted further comments on 
posted prices. Both agreed that posted prices no longer reflect market 
value. One commenter cautioned, however, that any use of gross proceeds 
to establish value (specifically in California) will result in 
royalties being paid on posted prices, since most outright sales 
contracts are tied to posted prices.
    MMS Response: For the reasons expressed in sections I and III(b), 
the final rule eliminates posted prices as an indicator of crude oil 
value for royalty purposes. However, MMS still believes that, even in 
California, proceeds received by a lessee or its affiliate under an 
arm's-length contract represent market value. Only when oil is not sold 
at arm's length is it necessary to look to other reliable indicators to 
determine value.
(b) Revisions to Arm's-length Valuation Criteria (Revised Proposed 
Paragraphs 206.102(a)(4) and (a)(6))
    Based on comments that the proposed rule overly restricted the use 
of arm's-length gross proceeds as royalty value, the July 1997 proposal 
expanded the arm's-length valuation criteria in proposed paragraph 
206.102(a)(4) by reducing the exclusions to only those situations 
involving (1) a sales contract that does not reflect the total 
consideration for the value of production, (2) a breach in the duty of 
the lessee to market production for the mutual benefit of the lessee 
and the lessor, (3) certain exchange agreements, (4) non-competitive 
crude oil calls, and (5) maintenance of overall balances between buyer 
and seller. For oil disposed of under a single arm's-length exchange 
agreement, MMS offered two options (revised proposed paragraph 
206.102(a)(6)): (1) the index pricing method, or (2) the gross proceeds 
received in an arm's-length sale of the oil acquired in the exchange. 
MMS also deleted the requirement that lessees use the index pricing 
method if they purchase oil within 2 years preceding the production 
month, commonly referred to as the ``two-year rule'' which was 
initially proposed as paragraph 206.102(a)(6).
    Summary of Comments--MMS Assumptions and Rationale: Sixteen 
respondents commented on MMS's underlying assumptions and rationale 
leading to the proposed revisions. Some thought the changes were in the 
right direction but, along with other commenters, believed the overall 
concept of index pricing and valuation away from the lease remained 
flawed because of the prevalence of active lease markets. A few 
commenters noted that the index pricing method is not applicable to 
Rocky Mountain oil because this oil stays in the RMR and its prices are 
not influenced by NYMEX trades.
    MMS Response: As discussed in Section III(g) and (h), index prices 
are often used in the negotiation of sales and settlement prices. They 
provide a reliable indicator of market value when oil is not sold at 
arm's length. For the RMR, however, the final rule contains a series of 
benchmarks for valuing oil not sold at arm's length. The first two of 
these benchmarks are not related to index prices. The third of these 
benchmarks is an index price--the Cushing, Oklahoma, spot price for WTI 
(adjusted for quality and location). MMS selected that price because it 
is closest to most of the RMR and is used in some exchange agreements 
involving oil produced in that region. However, under paragraph 
206.103(b)(5) of the final rule, if the lessee believes that the first 
three benchmarks do not result in a reasonable value for its 
production, the MMS Director will establish an alternate valuation 
method.
    Summary of Comments--Overall Balance: One commenter believed the 
restriction on ``overall balances'' (proposed paragraph 
206.102(a)(4)(ii)) is based upon an unproven and faulty assumption that 
reciprocal dealings are anti-competitive. Three commenters questioned 
the meaning of ``market value in the field or area'' regarding the 
limitation on overall balances. They believed the inclusion of this 
phrase would create confusion and litigation because despite the 
requirements to use index pricing in overall balance situations, 
companies might reason that the contract price nonetheless represents 
market value. Two commenters feared that MMS's use of

[[Page 14035]]

this phrase would open the door to the use of a comparable sales 
methodology, which they opposed. One commenter recommended that MMS 
modify the regulatory language on overall balance situations to 
provide:
    1. That index-based value be used where the arm's-length contract 
is subject to an informal or formal overall balance agreement 
maintained between the buyer and seller.
    2. That there is a rebuttable presumption that an overall balance 
arrangement exists where the lessee has purchased oil (or gas or other 
gas or petroleum-related products) from its buyer within the last 2 
years.
    3. That the rule does not apply for oil purchased to meet 
production shortfalls or for lease operations.
    Four commenters thought that a new certification to verify that a 
lessee is not maintaining an ``overall balance'' with its purchaser is 
unnecessary because Form MMS-2014 already certifies that values are 
true and accurate. They also suggested that ``overall balance'' be 
defined.
    MMS Response: MMS removed the language regarding overall balances 
as a separate, specific provision in the February 1998 proposal and in 
the final rule. However, oil subject to overall balance situations will 
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 overall balancing agreements thus ultimately will be the 
lessee's total consideration or the value determined by the non-arm's-
length methods in Sec. 206.103.
    Several commenters said in response to the February 1998 proposal 
that removing 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 and the provisions of paragraphs 206.102(c)(1) and (c)(2).
    Summary of Comments--Two-Year Rule: Two commenters opposed MMS's 
deletion of the ``two-year rule.'' One commenter argued that deleting 
this rule will cause difficult compliance problems because of the 
difficulty in tracing all two-party transactions and in determining the 
existence of overall balancing arrangements, many of which may be 
informal. To address the concerns of independent producers, two 
commenters recommended the 2-year rule be modified to exclude purchases 
of minimal amounts of crude oil for lease operations or to make up 
production shortfalls.
    MMS Response: As discussed in Section III(d) above, MMS removed the 
2-year rule because it was overly restrictive.
(c) Crude Oil Calls (Revised Paragraph 206.102(a)(4)(iii))
    For oil disposed of under a crude oil call, the July 1997 proposal 
would recognize gross proceeds as value only if the price paid is the 
same as what other parties are willing to competitively bid to purchase 
the oil (the so-called ``Most Favored Nations'' clause). Otherwise, oil 
disposed of under a non-competitive crude oil call would be valued by 
index pricing methods.
    Summary of Comments: Nine respondents commented on the crude oil 
call issue. There was general agreement to allow arm's-length sales of 
oil subject to unexercised crude oil calls to be valued based on gross 
proceeds. However, several commenters representing both State and 
industry interests expressed concern about the Most Favored Nations 
(MFN) clause. Four industry commenters disagreed that a crude oil call 
must contain a MFN clause for the sale of oil under the call to be 
considered arm's length. Commenters representing States, on the other 
hand, opposed treating contracts with crude oil calls with MFN or other 
escalation clauses as arm's-length, arguing that:
     The existence of an MFN clause in a contract does not mean 
the associated price was derived from a true arm's-length interaction.
     Acceptance of prices under MFN or other escalation clauses 
increases the potential to use oil postings as the basis for value.
     MMS will have difficulty in monitoring MFN transactions.
    Industry commenters recommended deleting reference to MFN 
altogether because such clauses are more common to gas contracts and 
rarely, if ever, are used in oil transactions. Industry commenters also 
generally opposed any exclusion of crude oil calls from arm's-length 
consideration, arguing that calls are legitimate business transactions 
and that MMS has the option to use benchmarks if call prices are 
suspect.
    MMS Response: MMS recognized in the July 1997 proposal that not all 
crude oil calls are exercised and that some calls are subject to 
competitive bid. In the February 1998 proposal, MMS modified the rules 
regarding competitive crude oil calls to accept arm's-length gross 
proceeds as value in these situations. In the final rule, MMS removed 
the language regarding noncompetitive crude oil calls as a separate, 
specific provision. However, oil subject to a noncompetitive crude oil 
call will 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 will 
be the lessee's total consideration or the value determined by the non-
arm's-length methods in Sec. 206.103.
(d) Valuing Oil Disposed of Under Exchange Agreements (Revised Proposed 
Paragraph 206.102(a)(6))
    The July 1997 proposal extended the use of gross proceeds valuation 
to oil exchanged and sold at arm's length after a single exchange. In 
those cases where a lessee disposes of the produced oil under an 
exchange agreement with a non-affiliated person, and after the exchange 
the lessee sells at arm's length the oil acquired in the exchange, the 
lessee would have the option of using either its gross proceeds under 
the arm's-length sale or the index pricing method to value the lease 
production (proposed paragraph 206.102(a)(6)(i)). If the lessee chose 
gross proceeds under this option, the lessee would have to value oil 
production disposed of under all other arm's-length exchange agreements 
in the same manner (proposed paragraph 206.102(a)(6)(iii)). For any oil 
exchanged or transferred to affiliates, or subject to multiple 
exchanges, the lessee would have to use the index pricing method to 
value the lease production (proposed paragraph 206.102(a)(6)(ii)).
    Summary of Comments: Ten respondents commented on the rules 
governing the valuation of oil disposed of under exchange agreements. 
Commenters supporting the amended proposal did so with reluctance. They 
believed the option to use gross proceeds would create compliance 
problems resulting from the necessity to trace and verify the nature of 
the exchange. One commenter suggested that MMS expand the gross 
proceeds option to apply to a single exchange by the lessee or its 
affiliate where all the oil received under that exchange is sold at 
arm's length. Two commenters suggested giving the lessee an option of 
valuing exchanged oil by using either lease-market benchmarks (rather 
than index prices) or the lessee's resale price less an exchange 
differential, regardless of the number of exchanges needed to 
reposition the crude oil for sale. Some commenters recommended 
excluding all exchange agreements from gross

[[Page 14036]]

proceeds valuation, as MMS initially proposed.
    MMS Response: 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, while others 
wanted the ability to use the ultimate arm's-length gross proceeds. As 
a result, and as explained in more detail in Section VI(e) of this 
preamble, in the final rule MMS is providing an option to use either 
the arm's-length gross proceeds following one or more arm's-length 
exchanges, or the provisions of Sec. 206.103. The chosen option will 
apply for at least 2 years. The lessee must use this method to value 
all of its crude oil produced on a property basis--that is, from the 
same unit, communitization agreement, or lease (if the lease is not 
part of a unit or communitization agreement) that the lessee or its 
affiliate sells at arm's length following one or more exchanges. (See 
Section IX (i) of this preamble for the reasons why the final rule 
changes to a property basis for this exception.) The provisions of 
Sec. 206.103 will apply for oil that is not sold at arm's length after 
the exchange and for oil subject to non-arm's-length exchanges 
regardless of whether an arm's-length sale follows such an exchange.
(e) NYMEX Pricing (Initial Proposed Paragraph 206.102(c)(2)(i))
    Summary of Comments: Nine respondents submitted further comments on 
the NYMEX pricing methodology proposed in the January 1997 proposal. 
Industry commenters reiterated their opposition to the methodology. Two 
commenters noted that NYMEX did not represent the market in California 
or Wyoming. However, one commenter defended the NYMEX market as a 
useful pricing reference for the oil industry. Contrary to industry's 
allegations that the NYMEX market is dominated by speculators, this 
commenter indicated that commercial oil entities account for 75 to 80 
percent of market participation.
    MMS Response: As discussed in Section III(g), MMS has abandoned the 
use of NYMEX prices as an indicator of crude oil value.
(f) ANS Spot Prices (Initial Proposed Paragraph 206.102(c)(2)(ii))
    Summary of Comments: Three industry commenters reiterated 
industry's general opposition to using ANS spot prices as the basis for 
crude oil valuation in California and Alaska. They argued that ANS spot 
prices are an invalid measure of California crude oil value because:
     The quality differences between ANS and California crudes 
are too great;
     ANS is a thinly-traded market; and
     ANS crude commands a higher price not only because of its 
superior quality but also because of its consistent availability to 
California refiners to satisfy marginal demands.
    Commenters representing the State of California continued to 
support the ANS valuation method for that State.
    MMS Response: For the reasons expressed in Section III(h), MMS 
maintains that the ANS spot price is a valid indicator of value for 
crude oil produced in California.
(g) Duty To Market (Initial Proposed Paragraph 206.102(e)(1))
    Summary of Comments: Seven respondents, five representing industry 
and two representing States, submitted further comments on the rule 
requiring lessees to market crude oil production at no cost to the 
Federal Government. Industry commenters repeated their opposition to 
this rule using the same reasons summarized for the January 1997 
proposal. However, State representatives supported the rule. One State 
commenter indicated that industry does not include marketing costs in 
determining location and quality differentials; therefore, industry 
should not be allowed to include marketing costs in determining the 
differentials for royalty purposes.
    MMS Response: For the reasons expressed in Section III(i), MMS 
maintains its position that lessees have a duty to market production 
without cost to the Government.
(h) Requiring Use of Actual Transportation Costs (Amended Sec. 206.105)
    Summary of Comments: Four respondents submitted further comments on 
the proposed removal of the exception regarding transportation 
allowance calculations based on actual costs. Industry commenters 
reiterated their opposition, while State commenters supported the 
proposal.
    MMS Response: As explained in Section III, in the final rule MMS 
has deleted the provision for a lessee to apply for an exception to use 
FERC tariffs in lieu of actual costs.
(i) Form MMS-4415 (Proposed Paragraph 206.105(d)(3)) and Differentials
    The July 1997 proposal clarified MMS's intended use of Form MMS-
4415 in two respects: (1) MMS will calculate specific differentials as 
the volume-weighted average of the individual differentials derived 
from the information reported on the form and (2) MMS will collect only 
information about exchanges where delivery occurs at an aggregation 
point and a market center (i.e., lessees will not be required to report 
information for exchanges occurring at the lease). MMS requested 
comments on the usefulness of collecting information about exchanges 
between two aggregation points. MMS also requested comments on how 
lessees would allocate to Federal leases differentials from aggregation 
points to market centers when non-Federal production is commingled with 
Federal production at aggregation points.
    Summary of Comments: Six respondents, five representing industry 
and one a local government, gave additional commentary on Form MMS-
4415. Few commenters responded directly to MMS's specific requests for 
comments on collecting information about exchanges between two 
aggregation points and allocating differentials when non-Federal 
production is commingled with Federal production at aggregation points. 
None gave substantive suggestions. Comments essentially duplicated 
those provided in response to the January 1997 proposal. Comments 
ranged from outright opposition to the form (and its data collection 
requirement) to complaints about its administrative burden and lack of 
clear instructions.
    MMS Response: As discussed in Section III(m), MMS eliminated Form 
MMS-4415 in the final rule.
(j) Fairness, Procedural Conduct, and Workability
    Summary of Comments: Ten respondents commented on this topic. 
Industry commenters continued to oppose any valuation scheme that they 
assert moves the point of royalty valuation away from the lease, 
reiterating their arguments that the index pricing methodology would 
not reflect market value at the time of production, would be costly and 
difficult to administer, and is contrary to lease terms and statutory 
mandates. They maintained their position that the value of oil disposed 
of under non-arm's-length conditions should be based on comparable 
transactions in the same field or area. Two commenters representing a 
State's interests criticized MMS for expanding the arm's-length gross-
proceeds valuation criteria.
    MMS Response: We responded to these comments throughout other 
sections of this preamble.

[[Page 14037]]

(k) Alternatives
    Summary of Comments: Eleven respondents (ten industry and one 
governmental advisory group) gave further comments on alternatives to 
the proposed rule. Industry commenters reiterated their position that 
MMS should either take its oil in kind (the most prevalent comment), 
modify the current benchmarks to eliminate reference to posted prices, 
or base value on some form of comparable sales from the same field or 
geographic area. However, related to an idea discussed in earlier 
public workshops, commenters said that a comparable sales valuation 
method based on data reported to MMS would be unworkable because of the 
limitations of MMS's computer system (MMS cannot sort the data by field 
nor determine significant quantities) and because much of the sales 
data reflects posted prices.
    MMS Response: We responded to these comments in detail in Section X 
and in Section III(r).

V. Responses to Public Comments on September 1997 Notice

Summary of Proposed Alternatives

    The September 1997 notice reopened the public comment period on the 
January 1997 proposal and requested comments on five alternatives to 
value oil disposed of under non-arm's-length conditions: (1) A value 
based on prices received under bid-out or tendering programs; (2) a 
value determined from benchmarks using arm's-length transactions, RIK 
sales, or a netback method; (3) a value based on geographic indexing 
using MMS's own system data, but excluding posted prices; (4) a value 
based on index (NYMEX and ANS) prices but using fixed-rate 
differentials; and (5) a value using published spot prices instead of 
NYMEX prices. With regard to Alternatives 1, 2, and 3, we asked whether 
the RMR should have separate and specific valuation standards.
    We received written comments from 28 entities, including 
independent oil and gas producers, major oil and gas companies, 
petroleum industry trade associations, States, a municipality, a 
government oversight group, and a royalty owner. Numerous individuals 
provided commentary at the public workshops. We summarized the comments 
on the proposed alternatives in the February 1998 proposal. We repeat 
the comment summaries here and give our responses.
(a) Alternative 1--Bid-Out or Tendering Program
    Summary of Comments: Industry and some States supported tendering 
as a viable method to determine royalty value. They reasoned that the 
prices received under tendering transactions were evidence of market 
value at or near the lease, which satisfies the rulemaking objective. 
However, industry cautioned that tendering would not be applicable in 
every situation (it would be too expensive for some companies to 
develop and administer) and should be one of the other alternatives 
available for valuation. In fact, two commenters noted that tendering-
based valuation was not feasible in California because no one is 
presently engaged in tendering programs in that State. To be acceptable 
for valuing the lessee's non-arm's-length production, one commenter 
recommended that the minimum tendered volume should be MMS's royalty 
share plus 2 percent, or if transported by a truck or tank car, a 
volume equal to a full load; another commenter recommended 10 to 20 
percent as the minimum volume, with a minimum of three bids.
    MMS Response: MMS did not adopt this alternative as there are 
meaningful spot prices applicable to production in all areas other than 
the Rocky Mountains. Further, tendering occurs in relatively few cases 
now and thus generally does not reflect true market value.
    With the exception of the RMR, 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. Thus, with 
the exception of the Rocky Mountains, we don't believe it is necessary 
to use other less accurate and more administratively burdensome means 
of valuing production not sold at arm's length (e.g., tendering).
    MMS adopted a particular tendering alternative designed with what 
MMS intends as safeguards against manipulation as a benchmark for the 
RMR 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 intends to 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 VI below.
(b) Alternative 2--Benchmarks
    Summary of Comments: Industry and some States generally supported 
some form of benchmark system based on actual arm's-length sales, RIK 
prices, or a netback method using an index price or affiliate's resale 
price to value oil not disposed of at arm's length. (Nonetheless, many 
commenters remained opposed to NYMEX- and ANS-based pricing.) Industry, 
however, advocated that lessees be permitted to select the valuation 
method best suited to their situation; in other words, they wanted the 
benchmarks to be a menu, rather than a hierarchy. States objected to 
this selection concept. Industry also urged MMS to abandon the 
requirement that royalty value is the greater of the lessee's gross 
proceeds or the benchmark value.
    One State recommended separate valuation standards for lessees with 
affiliated refiners and those without. For lessees with affiliated 
refiners, value would be determined by benchmarks using tendered 
prices, lease-based comparable sales, and netback from spot price. 
(This suggestion was directed to the RMR only.) For lessees without 
affiliated refiners, but who have a marketing affiliate that sells the 
lessee's oil outright or in a buy/sell exchange, royalty would be due 
on the resale value less appropriate allowances. Industry objected to 
this affiliated-refiners distinction because not all producers in 
integrated companies sell or transfer their oil production to their 
affiliated refiner.
    For netback valuation, industry urged MMS to recognize all costs 
associated with midstream marketing as allowable deductions from the 
index or resale price. However, one State commenter argued that 
industry has failed to demonstrate any entitlement to a marketing 
deduction as a matter of law or fact, citing, for example, that 
midstream marketing costs are already factored into transportation 
tariffs and location differentials.
    Two commenters representing State of California interests objected 
to any benchmark valuation scheme for that State. They argued that the 
California crude oil market is not competitive. Thus, they believed 
that any non-arm's-length valuation scheme based on arm's-length prices 
would not reflect true market value. They maintained that

[[Page 14038]]

ANS prices are the only viable method of valuing crude oil in 
California.
    MMS Response: In the final rule, MMS adopted a series of benchmarks 
for valuing RMR production not sold at arm's length. However, for the 
reasons explained above, the final rule does not use those benchmarks 
for the rest of the country; we apply spot prices in those regions. The 
Rocky Mountain benchmarks prescribe a first benchmark, but if it does 
not apply, the lessee has the choice of two other benchmarks. A lessee 
must use the first benchmark if it applies to the lessee's situation--
that is, tendering--and if tendering does not apply, then it may choose 
between a weighted average of arm's-length sales and purchases, or 
Cushing, Oklahoma, adjusted spot prices. If the lessee demonstrates 
that none of the three benchmarks establish a reasonable value, MMS may 
establish an alternative valuation method.
    MMS agreed with the industry comment that we should not require 
royalty value to be the higher of gross proceeds or the benchmark 
value. Hence, the final rule does not require royalty value to be the 
higher of gross proceeds or index price.
    While the final rule does not make a distinction between lessees 
with affiliated refiners and those without, it does establish different 
valuation methods for oil that is sold at arm's length versus oil that 
is not. The distinction is based on the disposition of the oil and not 
a lessee's ownership of a refinery.
    Comments regarding costs of midstream marketing are addressed in 
Section III(i).
(c) Alternative 3--Geographic Indexing
    Summary of Comments: Most commenters believed a geographic fixed 
index method would be unworkable. They mainly objected to the time 
difference between the production month and publication of the index 
price. They argued that the published indices would always be out-of-
date and require unnecessary adjustments for prior reporting months.
    MMS Response: MMS agrees with commenters that a geographic fixed 
index would be unworkable and, therefore, the final rule does not use 
this method. Additional MMS responses to this alternative are contained 
in our detailed responses to comments in Section XI, Executive Order 
12866, later in this preamble.
(d) Alternative 4--Differentials
    Summary of Comments: In concert with their objections to basing 
value on index (NYMEX and ANS) prices away from the lease, industry 
commenters opposed the use of any fixed (or other) differentials that 
don't permit deductions for midstream marketing activities. 
Specifically for California, two commenters representing State 
interests urged MMS to use the gravity factor in the Four Corners and 
All American Pipeline tariffs to adjust for quality differences between 
ANS and California crude oils. For location differentials, they 
reiterated their position that the only relevant information is from 
``in/out'' exchanges. As an alternative to determining separate 
location differentials for the various California aggregation point/
market center pairs, they proposed fixed-rate differentials for given 
geographic zones.
    MMS Response: MMS agrees with industry and most State commenters 
that the proposed fixed differentials would be unworkable and, 
therefore, the final rule does not use this method. The February 1998 
proposal and the final rule added paragraph 206.112(e) allowing for the 
use of quality banks including the gravity factor suggested by one 
State commenter. The final rule uses the location and quality 
differentials contained in arm's-length exchange agreements (including 
``in/out'' exchanges) to adjust index prices for location and quality. 
Additional MMS responses to this alternative are contained in our 
detailed responses to comments in Section XI, Executive Order 12866, 
later in this preamble.
(e) Alternative 5--Spot Prices
    Summary of Comments: Comments on the proposed spot price 
methodology were mixed. Some commenters thought it was a workable 
approach, but indicated that the net result would be the same as 
starting with a NYMEX price and adjusting back to the lease. A few 
commenters noted that spot prices are published only for a limited 
number of domestic crude oils, and no spot prices are published for the 
RMR. One commenter questioned the accuracy of the reported prices. 
Industry commenters remained concerned with the disallowance of 
marketing costs in any netback scheme.
    MMS Response: For regions other than the Rocky Mountains, the final 
rule uses spot prices to establish value for production not sold at 
arm's length. In the RMR, spot prices are used as a third benchmark. 
Additional MMS responses regarding use of spot prices are contained in 
detail in Section VI(e).
(f) Rocky Mountain Region
    Summary of Comments: There was general consensus that the RMR 
exhibited particular oil marketing characteristics that would justify 
different royalty valuation standards. Some commenters, both industry 
and State, supported the notion of separate valuation standards for the 
region. Others, however, disagreed with any regional separation, 
preferring instead a single, nationwide valuation scheme or menu of 
benchmarks.
    MMS Response: We agree with the general consensus that a separate 
valuation method is needed for the RMR. The final rule incorporates 
this change.

VI. Responses to Public Comments on February 1998 Proposal

Summary of Proposed Rule

    In response to comments received on the prior proposed rules and 
comments made at the public workshops, the February 1998 proposal 
contained substantive changes to the valuation procedures included in 
the January 1997 proposal. For oil that ultimately is sold in an arm's-
length transaction, the royalty value would be the gross proceeds 
accruing to the seller under the arm's-length sale. This procedure 
would apply to arm's-length exchanges where the oil received in 
exchange is ultimately sold at arm's length. It would also apply to oil 
sold in the exercise of competitive crude oil calls.
    For oil (or oil received in exchange) that is refined without being 
sold at arm's length, for oil disposed of under non-arm's-length 
exchange agreements and non-competitive crude oil calls, and for all 
other oil not sold at arm's-length, the royalty value would be 
determined by measures prescribed for three geographic regions. For oil 
produced in California and Alaska, value would be based on ANS spot 
prices, adjusted for location and quality. For oil produced in the RMR, 
value would be determined by the first applicable of four benchmarks: 
(1) The highest price bid for tendered volumes, (2) the volume-weighted 
average of gross proceeds accruing under the lessee's or its 
affiliate's arm's-length contracts for the purchase or sale of crude 
oil from the field or area, (3) the average NYMEX futures prices, with 
location and quality adjustments, and (4) an MMS-established method. 
For oil produced outside of California, Alaska, and the Rocky Mountain 
Area, value would be the average of the daily mean spot prices 
published for the nearest market center, adjusted for location and 
quality differentials.
    The February 1998 proposal also contained specific instructions for 
reporting on Form MMS-4415, modified

[[Page 14039]]

certain definitions, and added others. It reiterated the lessee's duty 
to put the production in marketable condition and to market the 
production at no cost to the lessor. Rules addressing transportation 
allowances were recodified in new sections and modified to reflect the 
newly-proposed valuation rules.
    We received almost 700 pages of written comments from 35 entities, 
including independent oil and gas producers, major oil and gas 
companies, petroleum industry trade associations, States, a 
municipality, small refiners, and consultants. Consistent with its past 
comments, industry generally opposed the proposed rules, arguing that 
they do not offer certainty, do not reduce administrative costs, and 
particularly do not derive a reasonable value of production at the 
lease. Industry particularly maintained its advocacy of using so-called 
``lease markets'' (arm's-length sales of like-quality production in the 
same field or area) to set value of production not disposed of at arm's 
length. States generally supported the rule but had suggestions for 
changes.
    Several commenters continued to address many of the same issues. 
They include:
     Duty to market,
     Restrictions on gross proceeds valuation,
     Using NYMEX index prices and ANS spot prices for non-
arm's-length valuation,
     Treatment of non-competitive crude oil calls,
     Eliminating the exception allowing requests to use FERC 
tariffs instead of actual transportation costs, and
     Use of differentials to calculate royalty value.
    Comments on these issues were not substantively different from 
those previously summarized. Rather than repeating the issues and 
comments here, we refer the reader to Sections I, III, IV, and V above. 
Instead, we only address comments on those provisions that are new to 
or revised from the previous proposals. Comments are grouped into seven 
topical categories ((a) through (g) below).
(a) Definitions (Proposed Sec. 206.101)
    Affiliate--Summary of Comments: Eleven respondents, all 
representing industry, objected to the 10 percent ownership threshold 
for defining control and thus requiring non-arm's-length valuation. 
They argued that 10 percent was too low because affiliates with this 
small amount of ownership actually have no control over the affiliated 
entity. Accordingly, they believed that too many lessees would be 
excluded from using their gross proceeds in bona fide arm's-length 
transactions as value. Others suggested retaining the current 
definition of affiliate, as defined by the term ``arm's-length 
contract,'' where ownership of 10 percent through 50 percent creates a 
presumption of control. One commenter suggested 20 percent to 50 
percent ownership as the criteria for creating a presumption of 
control, consistent with the definition used by the Bureau of Land 
Management. One commenter suggested deleting reference to partnerships 
and joint ventures because lessees might not have access to records of 
these entities and these terms could create confusion as to whether the 
affiliate test applies to the property, field, or corporate level.
    MMS Response: In this final rule, we have made ``affiliate'' a 
separate definition from ``arm's length.'' We believe this clarifies 
and simplifies the definitions and should promote better understanding 
of both ``arm's length'' and ``affiliate.''
    In the final rule, MMS is revising the definition of ``affiliate.'' 
The July 1998 proposal (63 FR at 38356) retained the criteria for 
determining affiliation that are contained in the existing rule. The 
March 1999 notice that included the August 31, 1998 letter from the 
Assistant Secretary for Land and Minerals Management to the Senate (64 
FR at 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 comment 
period for the March 1999 notice 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 5. 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 C.F.R. 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.

Id. The United States did not file a petition for rehearing. Nor did 
the United States seek Supreme Court review.
    In the final rule, 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, paragraph 
(2) of the definition in the final rule, instead of creating a 
presumption of control, identifies a number of factors that MMS will 
consider in determining whether there is control under the 
circumstances of a particular case.
    With respect to ownership or common ownership, the new definition 
identifies 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

[[Page 14040]]

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.)
    Paragraph (2) of the 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 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 will be evaluated on a case-
by-case basis.
    Paragraphs (1) and (3) of the definition continue the existing 
provisions that ownership of more than 50 percent constitutes control, 
that ownership of less than ten percent constitutes a presumption of 
noncontrol, and that relatives, either by blood or marriage, are 
affiliates regardless of any percentage of ownership or common 
ownership. The National Mining Association decision does not affect 
these provisions.
    Gross proceeds--Summary of Comments: Two industry commenters 
opposed the inclusion of payments made to reduce or ``buy down'' the 
purchase price of oil to be produced in later periods in the revised 
definition of ``gross proceeds.'' One commenter argued that the 
collection of royalty on buydowns was contrary to the decision in IPAA 
v. Babbitt, 92 F.3d 1248 (D.C. Cir. 1996).
    MMS Response: The implications of the D.C. Circuit's ruling in the 
IPAA case, as well as the Sixth Circuit's decision in United States v. 
Century Offshore Management Corp., 111 F.3d 443 (6th Cir. 1997), cert. 
denied, 522 U.S. 1090 (1998), and other subsequent court decisions 
regarding ``buydown'' payments (which in recent years have been part of 
contract settlement arrangements) are analyzed in two recent decisions 
of the Assistant Secretary for Land and Minerals Management in Mobil 
Oil Corp., Docket Nos. MMS-94-0151-OCS, 94-0668-O&G, 94-0669-O&G, 95-
0063-O&G, and 95-0065-O&G (consolidated) (May 4, 1998), and Antelope 
Production Co., Docket No. MMS-96-0068-O&G (May 4, 1998). For the 
reasons explained in those decisions, the definition of ``gross 
proceeds'' contained in the February 1998 proposal and in the final 
rule is fully in accordance with law.
    Rocky Mountain Area--Summary of Comments: Six respondents (five 
industry and one State) commented on the definition of ``Rocky Mountain 
Area.'' Industry commenters believed the word ``Area'' should be 
changed to ``Region'' to avoid confusion with the definition of 
``area.'' They also suggested including northwest New Mexico (i.e., the 
San Juan Basin) in the Rocky Mountain Area. The State commenter, 
however, opposed including northwest New Mexico in the definition 
because crudes from the San Juan Basin are regularly exchanged in 
midcontinent markets.
    MMS Response: MMS agrees with the comment that the term Rocky 
Mountain ``Area'' should be changed to Rocky Mountain ``Region.'' We 
made this change in the final rule. We concur with the commenter from 
the State of New Mexico that northwest New Mexico should not be part of 
the RMR because crude oil from the San Juan Basin is regularly 
exchanged or sold in midcontinent markets. For the same reasons, the 
final rule excludes from the RMR definition those portions of the San 
Juan Basin, and other oil-producing fields in the ``Four Corners'' area 
(i.e., near the convergence of the boundaries of New Mexico, Arizona, 
Utah, and Colorado) that lie within the States of Colorado and Utah. 
Crude oil produced from these areas typically is exchanged or sold in 
midcontinent markets for which dependable index prices are published. 
MMS therefore believes it is appropriate that the index values from 
those markets be used in valuing production not sold at arm's length or 
for which the lessee opts to use index values under other provisions of 
the final rule, as explained below.
    Suggested ``Operating Allowance'' Definition--Summary of Comments: 
We received a comment that ``operating allowance'' needs to be included 
in the definitions section. The commenter said it is still unclear what 
is meant by an operating allowance, both in this section and its 
predecessor section.
    MMS Response: The operating allowance language was added to 30 CFR 
206.106 in 1996 as part of a new rule on bidding systems for leases on 
the OCS. Operating allowances are to be predetermined and defined at 
the time of a lease sale. They may be used either to effectively 
replace the valuation regulations to calculate net receipts subject to 
the nominal royalty rate, or to reduce net receipts after the valuation 
regulations are applied to determine receipts subject to the nominal 
royalty rate. In either case, the approach used would be specified in 
the lease sale notice. Such allowances would be in lieu of any 
allowances that otherwise might have applied under the valuation rules. 
We chose not to define ``operating allowance'' so as not to confuse the 
application of allowances otherwise permitted under 30 CFR part 206 
with the operating allowance concept. Any lessee with an operating 
allowance will be fully aware of its specifics regarding the applicable 
lease, because it will be defined explicitly in the notice of lease 
sale.
(b) Tracing Exchange Transactions (Proposed Paragraph 206.102(c)(3))
    The February 1998 proposal expanded gross proceeds valuation to oil 
that is sold at arm's length after being involved in one or more arm's-
length exchanges. This provision would have required the lessee to 
trace the oil through all such exchanges to assure they are all arm's 
length and to capture all location and quality differentials. If the 
lessee then sold at arm's length the oil it ultimately received, the 
value of the oil produced from the lease would have been the gross 
proceeds for the oil ultimately sold after the exchanges, adjusted for 
any location and quality differentials incurred in the course of the 
arm's-length exchanges.
    Summary of Comments: Seventeen respondents (fourteen industry, two 
States, and one municipality) commented on the tracing aspect of the 
rule. They all agreed that tracing oil through multiple exchanges would 
be impractical, if not physically impossible, because of aggregation 
and commingling of Federal and non-Federal crudes of different 
qualities and the magnitude of administering a program to track 
individual exchange transactions. A few commenters asserted that the 
sharing of information about oil exchanges might violate United States 
antitrust laws.
    One State commenter recommended confining gross proceeds valuation 
to an arm's-length first sale. Another commenter was concerned that 
Federal royalty oil could be valued at the lowest price received when 
there are multiple sales at the end of a series of exchanges.
    As an alternative to tracing, one company suggested that the value 
of oil

[[Page 14041]]

disposed of through arm's-length exchanges be based on the spot market 
price of the crude oil received, adjusted for location and quality 
differentials received or paid. An industry trade organization 
recommended replacing the tracing method with either: (1) Royalty 
valuation procedures (RVP's) based on arm's-length sales from nearby 
wells, or (2) a netback procedure. Some industry commenters were 
concerned that the proposed rule gave MMS too much latitude to disallow 
transactions under arm's-length exchange agreements, which would create 
uncertainty by allowing auditors to second-guess a company's marketing 
decisions.
    MMS Response: The July 1997 proposal extended the use of gross 
proceeds valuation to oil exchanged and then sold at arm's length. In 
those cases where a lessee disposed of the produced oil under an 
exchange agreement with a non-affiliated person, and after the exchange 
the lessee sold at arm's length the oil acquired in the exchange, the 
lessee would have had the option of using either its gross proceeds 
under the arm's-length sale or the index pricing method to value the 
lease production (proposed paragraph 206.102(a)(6)(i)). This option 
would have applied only when there was a single exchange. If the lessee 
chose gross proceeds under this option, the lessee would have valued 
all oil production disposed of under all other arm's-length exchange 
agreements in the same manner (proposed paragraph 206.102(a)(6)(iii)). 
For any oil exchanged or transferred to affiliates, or subject to 
multiple exchanges, the lessee would have used the index pricing method 
to value the lease production (proposed paragraph 206.102(a)(6)(ii)).
    Participants in MMS's workshops held in October 1997 indicated that 
they often use several exchanges to transport their production from 
offshore leases to market centers onshore. They believed that MMS 
should give the lessee an option of valuing exchanged oil either by 
using so-called ``lease-market'' benchmarks (rather than index prices) 
or by using the lessee's resale price less an exchange differential, 
regardless of the number of exchanges needed to reposition the crude 
oil for sale.
    In response to those comments, in the February 1998 proposal MMS 
expanded gross proceeds valuation to include situations where the oil 
received in exchange is ultimately sold arm's length, regardless of the 
number of arm's-length exchanges involved. However, because many 
industry comments claimed that tracing multiple exchanges would be 
overly burdensome, while others wanted the ability to use the ultimate 
arm's-length gross proceeds, in the final rule, MMS is providing an 
option to use either the arm's-length gross proceeds following one or 
more arm's-length exchanges, or the provisions of Sec. 206.103. The 
chosen option will apply for at least 2 years, and the lessee must use 
this method to value all of its crude oil produced from the same unit, 
communitization agreement, or lease (if the lease is not part of a unit 
or communitization agreement) that the lessee or its affiliate sells at 
arm's length following one or more exchanges. The provisions of 
Sec. 206.103 will apply for oil that is not sold at arm's length after 
the exchange, as well as to oil subject to non-arm's-length exchanges. 
We included these qualifications to assure that lessees will not abuse 
the system by choosing case-specific options or time periods that best 
suit their situations, or by using non-arm's-length exchange 
differentials to determine royalty value.
    As discussed elsewhere in this preamble, the final rule does not 
use the industry's suggested ``RVP's.'' In the RMR, however, the final 
rule uses a prescribed series of benchmarks similar to the suggested 
``RVP's,'' for reasons explained elsewhere in this preamble. Also, as 
discussed elsewhere in the preamble, MMS believes that except for the 
RMR, spot prices are the best indicators of value.
    The lessee's duty to market does not mean that MMS will second-
guess a company's marketing decisions. Lessees may structure their 
business arrangements however they wish, and, absent misconduct or 
breach of the lessee's duty to market to the benefit of itself and the 
lessor, MMS will look to the ultimate arm's-length disposition in the 
open market as the best measure of value.
(c) Different Geographic Regions (Proposed Sec. 206.103)
    Based on the isolation of the West Coast petroleum market and its 
distinctive market conditions, the previous rulemaking proposals 
recognized two geographic regions for valuation: (1) California and 
Alaska and (2) the remainder of the country. However, from the comments 
received on these proposals, it became apparent that oil marketing in 
the RMR is significantly different. Accordingly, the February 1998 
proposal recognized three regions for royalty valuation: (1) California 
and Alaska, (2) the RMR, and (3) the rest of the country.
    Summary of Comments: Four respondents representing industry 
commented on the three-region approach; all opposed it. They claimed 
that the geographically different valuation standards will require 
companies to install additional computer systems or systems software 
and hire corresponding additional staff. One respondent recommended 
revising the existing non-arm's-length valuation benchmarks to provide 
universal valuation procedures that would determine value at the lease.
    State participants at MMS's October 1997 workshops supported 
different valuation methods for different regions of the country.
    MMS Response: There was general consensus among commenters that the 
RMR exhibited particular oil marketing characteristics that would 
justify different royalty valuation standards. Production is controlled 
by relatively few companies in the RMR; the number of buyers is also 
more limited than in the Gulf Coast and midcontinent regions; and there 
are limited third-party shippers, resulting in less competition for 
transportation services in this region. There is less spot market 
activity and trading in this region as a result of the control over 
production and refining. Finally, crude oil production in the RMR 
typically involves much smaller volumes and is more scattered than in 
the Gulf Coast and midcontinent regions.
    Beginning with the January 1997 proposal, MMS has maintained a 
separate valuation methodology for production in California and Alaska. 
As explained thoroughly in previous proposals, the California and 
Alaska markets are unique and warrant different valuation methods. The 
final rule maintains this difference and thus establishes three regions 
including (1) California and Alaska, (2) the RMR, and (3) the rest of 
the country.
    Industry stated that new computer systems are needed, with the 
possibility of three separate systems for the three regions of the 
country with separate valuation requirements. However, they did not 
provide any rationale as to why, or any specifics on how those computer 
systems would be different than what they need under the current 
regulations. The majority of payors will continue to pay on the gross 
proceeds received under an arm's-length sale just as they always have. 
This means that they will not incur any additional computer costs or 
time in complying with the arm's-length provisions of the new rule. For 
those not paying on gross proceeds, industry has not shown that the 
methods applicable to the three different regions of the country will 
require unduly complicated or costly computer systems overhaul or 
substantial additional staff. We

[[Page 14042]]

recognize, however, that the changes in valuation methodology will 
require some systems changes. For that reason the final rule includes a 
``grace period'' for royalty adjustments necessitated by system 
changes. The grace period includes the first three production months 
following the effective date of the rule. There will be no liability 
for late payment interest during this period. The final rule includes 
three geographic regions as contained in the February 1998 proposal.
(d) Restrictions on Rocky Mountain Region Benchmarks (Proposed 
Paragraph 206.103(b))
    Under the February 1998 proposal, the value of crude oil produced 
in the RMR and not sold at arm's length would be determined by the 
first applicable of the following benchmarks:
    (1) For lessees with an MMS-approved tendering program, value of 
production from leases in the area covered by the tendering program 
would be the highest price bid for the tendered volumes. To exercise 
this benchmark, the lessee would have to offer and sell at least 33\1/
3\ percent of its total Federal and non-Federal production from that 
area under the tendering program and 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.
    (2) A value calculated as the volume-weighted average of the gross 
proceeds accruing to the lessee or its affiliate for arm's-length 
purchases or sales of production from the field or area during the 
month. The total volume purchased or sold under the arm's-length 
transactions must exceed 50 percent of the lessee's or its affiliate's 
Federal and non-Federal production from the same field or area during 
that month.
    (3) A value calculated as 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, adjusted for 
location and quality differentials.
    (4) If the lessee demonstrates to MMS's satisfaction that the first 
three benchmarks result in an unreasonable value for its production, 
the MMS Director may establish an alternative valuation method.
    Summary of Comments--Tendering: Six respondents, all representing 
industry, commented on benchmark 1 (tendering). They all opposed the 
restrictions, claiming they were excessive and would all but eliminate 
tendering as a measure of value. Comments included:
     The method MMS used to arrive at the one-third volume 
requirement is flawed because if the lease is Federal, there is no 
State royalty or tax interest involved. Likewise, if the lease is a 
State lease, there is no Federal interest involved. Requiring one-third 
of the lessee's total production is onerous as a practical matter; a 
more reasonable volume would be 15 or 20 percent.
     Lessees have no control over the number of bids received. 
Together with the limited number of producers in the Rocky Mountain 
Area, the three-bid restriction would negate tendering as a viable 
benchmark in many cases.
     The use of the highest bid is unreasonable unless all the 
bids happen to be for the full tendered volume.
     If the lessee has a refining affiliate, that affiliate 
would be disqualified from bidding on oil tendered by others, while at 
the same time being excluded from buying at least one-third of its 
affiliated lessee's own production.
    A few commenters thought that tendering, without the restrictions, 
would offer a viable valuation tool, not only for the RMR but 
nationwide.
    MMS Response: MMS added the several qualifications stated above to 
ensure receipt of market value under tendering programs. First, royalty 
value must be the highest price winning bid rather than some other 
individual or average value. We believe this is necessary to assure 
receipt of market value.
    Second, MMS acknowledges that the minimum tendered volume could be 
less than 33 \1/3\ percent, but only by a small amount. In the final 
rule, you must offer and sell at least 30 percent of your production 
from both Federal and non-Federal leases in that area. MMS wants to 
ensure that the portion put up for tendering at least covers the 
Federal royalty interest and the composite State effective tax rate on 
oil production. That combination typically ranges from about 17 percent 
to about 27 percent. These percentages do not include State royalty 
rates, which did not enter into the calculation. 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 ``game'' the system for Federal royalty or 
State tax payment purposes. In this final rule, we thus chose 30 
percent 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 must include 
non-Federal lease production volumes in the 30 percent determination to 
ensure that the program isn't aimed at limiting Federal royalty value.
    In our February 1998 proposal, we stipulated a minimum of three 
bids. However, 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 the final rule. Further, MMS is concerned 
about the possibility of companies cross-bidding at below-market 
prices. That is why in the final rule we have retained the stipulation 
that the minimum of three bids must come from bidders who do not also 
have their own tendering programs in the area.
    Summary of Comments--Weighted Average Gross Proceeds: Five 
respondents, four industry and one State, commented on benchmark two 
(weighted-average gross proceeds). Comments included:
     The 50-percent arm's-length-sales threshold is too high. 
There is no reasonable justification for this percentage. Twenty to 25 
percent is a sufficient statistical percentage to establish value.
     Where oils of different qualities are produced in the same 
field or area, the weighted-average method could lead to undervaluing 
of high-quality oils. Lessees can game the system by buying low-quality 
crudes and reporting their weighted-average value for high-quality 
crudes.
     Any discounting of prices for certain volumes would lead 
to inaccurate weighted averages.
     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 requires 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. The commenters said 
this ``tracing'' would be difficult at best. 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.

[[Page 14043]]

    MMS Response: MMS developed this method as the next alternative if 
a qualified tendering program does not exist. (One of the Rocky 
Mountain State commenters recommended that the alternatives be given in 
this order). This method is an effort to establish value based on 
actual transactions by the lessee and its affiliate(s). 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 ``gaming.'' 
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 applies to the lessee's and its 
affiliates' sales and purchases in the field or area, rather than just 
sales. (The tendering program involves only sales.)
    We also received a comment expressing concern that lessees would 
have to perform additional work each month to determine whether they 
met the 50 percent threshold. In response to this concern, the final 
rule permits the option that if the first benchmark does not apply, the 
lessee may apply either the second or third benchmarks. Thus, if the 
lessee believes the continuing work involved in determining whether 
they meet the 50 percent threshold is too great, they may apply the 
third benchmark (spot prices at Cushing, Oklahoma, adjusted for 
transportation and quality differences).
    This final rule requires using a gravity-adjusted 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 the method in the February 1998 proposal would 
result in improper valuation of some oil that was significantly 
different in quality than that associated with the ``average'' oil. In 
general, we believe that production in the same field or area will be 
similar in quality. However, in response to comments, in the final rule 
we require that before calculating the volume-weighted average, you 
must normalize the quality of the oil in your or your affiliate's 
arm's-length purchases or sales to the same gravity as that of the oil 
produced from the lease. Further, given that these sales and purchases 
must 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.
    We cannot agree with the comment that oil resold by a marketing 
affiliate of the producer should be valued using this benchmark. 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. To do otherwise would be inconsistent with the way arm's-
length resales are treated elsewhere in this rule. However, this final 
rule offers the option that where the production is sold or transferred 
to an affiliate who then resells it, the lessee could value its 
production using Sec. 206.103 rather than the affiliate resale price. 
This does not mean that MMS believes the affiliate's arm's-length 
resale price should not form the valuation basis; rather, we are 
accommodating those who say ``tracing'' production is a problem by 
offering an alternative that should ease their administrative burden 
while still providing a fair royalty value. MMS is willing to permit 
this option because it anticipates that overall the index prices used 
under Sec. 206.103 will approximately reflect what affiliated marketing 
entities are able to obtain under most circumstances.
    Summary of Comments--NYMEX Futures Prices: Nine respondents, all 
representing industry, commented on benchmark three, NYMEX futures 
prices. Consistent with industry's previous position on NYMEX prices 
(i.e., the futures market bears little relation to lease markets; see 
Sections III and IV), they all opposed NYMEX pricing as a measure of 
value for the RMR. One commenter pointed out the difficulty of applying 
NYMEX sweet prices to Wyoming sour crude.
    MMS Response: As discussed in Section III(g) of this preamble, the 
final rule does not use NYMEX futures prices as a measure of value. 
Instead, MMS chose to use spot prices because studies indicated that 
when NYMEX prices, properly adjusted for location and quality 
differences, are compared to spot prices, they nearly duplicate those 
spot prices. Further, except for the RMR, application of spot prices 
removes one portion of the adjustments to the NYMEX price that would 
have been needed--the leg between Cushing, Oklahoma, and the market 
center location.
(e) Spot Prices (Proposed Paragraph 206.103(c))
    Under the February 1998 proposal, the value of crude oil produced 
outside California, Alaska, and the RMR and not sold at arm's length 
was the average of the daily mean spot prices for deliveries during the 
production month:

--For the market center nearest the lease where spot prices are 
published in an MMS-approved publication and
--For the crude oil most similar in quality to the lease crude.

    The average spot prices would be adjusted for location and quality 
differentials and for transportation costs to derive the royalty value.
    Summary of Comments: Thirteen respondents--twelve industry and one 
State--commented on spot prices as a measure of value. One industry 
respondent supported the change from NYMEX-based pricing to spot 
prices, stating that the change bases valuation on a crude oil more 
similar in quality and at a location closer to the lease while 
eliminating an adjustment step in the valuation process that is prone 
to error.
    The remaining eleven industry respondents opposed the use of spot 
prices (along with any other index pricing method) to value crude oil 
production. Their arguments included:
     Spot prices do not accurately reflect lease values. Spot 
prices represent the cost of obtaining crude oil for delivery within 30 
days. By contrast, a great deal of market activity is accounted for by 
longer-term arrangements.
     Spot prices do not move in lock-step with local markets; 
they do not reflect the influence of local supply and demand.
     Spot prices capture downstream value enhancements; 
differential adjustments are inadequate to compensate for the value 
added by moving the production from the lease to a market center.
     Spot prices published by commercial news services are 
based on limited polling of traders; there is no uniform calculation 
method and accuracy is dependent on the reporter's judgment.
    The State commenter disagreed with abandoning NYMEX prices for spot 
prices. This commenter contended that NYMEX prices better reflect 
market value because NYMEX transactions constitute a much larger volume 
of trades than spot markets and because the NYMEX market is less 
subject to manipulation than spot markets.
    MMS Response: The body of evidence regarding actual marketing 
practices indicates that index prices, including spot prices, play a 
significant role in setting contract prices. The final rule maintains 
the use of ANS spot prices in California for oil not sold at arm's 
length. Location- and quality-adjusted spot prices, rather than NYMEX 
futures

[[Page 14044]]

prices, also are used for oil not sold at arm's length for oil produced 
elsewhere. (For the RMR, spot prices at Cushing, Oklahoma, are used as 
the third benchmark.) We believe that the location and quality 
adjustments together with the transportation allowances specified in 
the final rule effectively result in market value at the lease. 
Similarly, even though spot prices are not established directly for all 
local markets, we believe that the location and quality adjustments do 
result in reasonable measures of value in the local markets.
    However, we believe that in some cases the use of spot prices 
determined before the production month, as proposed in February 1998, 
could affect lessees' production decisions and, ultimately, royalties 
paid. Therefore, in the final rule, we have adopted the procedure for 
applying spot prices proposed in January 1997, rather than the 
procedure proposed in February 1998, for the following reasons.
    Assume the average daily spot price in an MMS-approved publication 
is determined April 26-May 25 for the delivery month of June. Further 
assume that the lessee transfers its production to an affiliated 
marketing entity who then resells at arm's length and that the lessee 
has opted to value the production at the index price. The lessee 
responsible for reporting June production volumes and values would then 
know the June spot price (and therefore the royalty value) by the end 
of May, before its production for the month of June even begins. If the 
daily spot price then rose through the rest of May and the early part 
of June, the lessee might decide to increase production over at least a 
short period and thereby realize more per barrel than the royalty 
value. Conversely, if the daily spot price fell after May 25 and into 
early June, the lessee might decide to decrease production so as to be 
impacted minimally by realizing less per barrel than the index price it 
must use for royalty payments. To prevent such potential problems, the 
final rule applies the spot price effectively determined during the 
production month so that the price determination is concurrent with 
production. So, for example, for May production in the Gulf of Mexico 
you would use the spot price determined from April 26 through May 25 
for June delivery.
    Several commenters said that use of a spot price improperly 
captures downstream value enhancements and that the differentials 
specified by MMS are inadequate. We covered this issue thoroughly in 
Section III(i) earlier in this preamble. We point out again here that 
MMS has never allowed deductions from royalty value for marketing 
costs. This rulemaking makes no change to the lessee's duty to market. 
Valuation based on a ``downstream'' sale or disposition of production 
has been commonplace for many years, because the initial basis for 
establishing value often is a ``downstream'' sales price. 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.
    One of the real issues between industry and MMS is what costs 
should be allowed as part of the transportation function. The industry 
would like more costs included as part of transportation than MMS is 
willing to allow. MMS has prescribed by rule what transportation costs 
are deductible, and believes that the allowed costs are proper.
    Finally, MMS believes the available spot prices represent accurate 
assessments of day-to-day oil market value. MMS has reviewed the 
procedures used by the major price reporting services. While it is true 
that spot prices result from surveys done by individuals, we believe 
their procedures and safeguards produce meaningful value assessments. 
Further, comparisons of spot prices with NYMEX futures prices show a 
direct correlation between the two when appropriate location and 
quality adjustments are made. We did find some spot price locations--
for example, Guernsey, Wyoming, and Kern River and Line 63 in 
California--where the volumes traded were so limited that we didn't 
believe we should rely on the resulting spot price. We did not use 
those spot prices in the final rule.
(f) Nonbinding Valuation Guidance (Proposed Sec. 206.107)
    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.
    Summary of Comments: Three industry commenters were concerned with 
the nonbinding nature of the guidance. As stated by one of the 
commenters:
     MMS offers no explanation for abandoning the current 
regulations, which don't specify that value determinations are 
nonbinding.
     As a practical matter, a lessee would not seek a 
nonbinding value determination.
     If the guidance is favorable to the lessee, MMS would not 
be bound by it. (In other words, MMS could change its mind at a future 
date.)
     If the guidance is unfavorable to the lessee, it might be 
at risk for civil penalties for willfully and knowingly not complying 
if it disregards the guidance; yet the lessee has no recourse to appeal 
the guidance.
    MMS Response: In the final rule, in response to comments, we are 
providing a procedure for valuation determinations that is more than 
simply non-binding guidance. Under Sec. 206.107 of the final rule, you 
may request a value determination from MMS regarding any Federal lease 
oil production. (Your request must identify all leases involved, the 
record title or operating rights owners, and the designees for those 
leases, and explain all relevant facts.) MMS may either:
    (1) Issue a value determination signed by the Assistant Secretary, 
Land and Minerals Management; or
    (2) Issue a value determination by MMS; or
    (3) Decline to provide a value determination.
    A value determination signed by the Assistant Secretary, Land and 
Minerals Management, is binding on both you and MMS until the Assistant 
Secretary modifies or rescinds it. It is also the final action of the 
Department and is subject to judicial review under the Administrative 
Procedure Act, 5 U.S.C. 701-706.
    In contrast, a value determination issued by MMS is binding on MMS 
and delegated States with respect to the specific situation addressed 
in the determination, unless the MMS or the Assistant Secretary 
modifies or rescinds it. In the December 1999 proposal, we used the 
term ``MMS Director'' instead of ``MMS''. We changed the reference to 
``MMS'' so that it was clear that the Director could delegate this 
authority, for example, to the Associate Director for Royalty 
Management.
    Further discussion of States' concerns on their input to value 
determinations is provided at Section IX (u) of this preamble.
    A value determination by MMS is not an appealable decision or order 
under 30 CFR part 290 subpart B. If you receive an order requiring you 
to pay royalty on the same basis as the value determination, you may 
appeal that order under 30 CFR part 290 subpart B.
    A few commenters at the January 2000 public workshops asked MMS to 
specify that if a lessee chooses not to follow a value determination by 
MMS, it will not be subject to civil penalties under FOGRMA section 
109(c), 30 U.S.C. 1719(c), for knowing or willful underpayment of 
royalties. A decision

[[Page 14045]]

not to follow an MMS value determination will not, in and of itself, 
result in a civil penalty assessment for knowing or willful 
underpayment. However, it does not immunize the lessee from penalties 
for knowing or willful violations if the lessee's conduct constitutes a 
knowing or willful underpayment independent of the MMS value 
determination.
    Importantly, a change in an applicable statute or regulation on 
which any value determination is based takes precedence over the value 
determination. It is not necessary for the MMS or the Assistant 
Secretary to modify or rescind the value determination for the new 
statute or rule to take precedence.
    With certain exceptions, a value determination may be modified only 
prospectively. However, the MMS or the Assistant Secretary may modify 
or rescind a value determination retroactively if there was a 
misstatement or omission of material facts in your request, or if the 
facts subsequently developed are materially different from the facts on 
which the guidance was based. In situations such as these, the agency 
should not be bound by a value determination.
    Situations in which MMS typically will not provide any value 
determination include, but are not limited to, requests for guidance on 
hypothetical situations and matters that are the subject of pending 
litigation or administrative appeals. MMS also typically will not use a 
value determination to resolve factual disputes either between MMS and 
the lessee, or between the lessee and third parties (for example, a 
purchaser) where those disputes are relevant to royalty value. While 
MMS will respond to requests for value determinations, it is not 
obligated to issue a value determination.
    Value determinations are issued only under Sec. 206.107, in 
response to a specific request for a value determination. Under other 
provisions of the rule, lessees may ask MMS to make certain other 
determinations--for example, to establish a location/quality adjustment 
under Sec. 206.112, or even (as the fourth benchmark for non-arm's-
length dispositions in the RMR under Sec. 206.103(b)) to establish a 
valuation method.
(g) Adjustments and Transportation Allowances (Proposed Secs. 206.109 
through 206.112)
    Summary of Comments: Twenty respondents, including sixteen 
representing industry, three representing States, and one representing 
a municipality, commented on various aspects of location and quality 
adjustments and transportation allowances. Industry continued to 
oppose: (1) Differentials that do not allow all post-production 
marketing costs and services; (2) the elimination of the exception 
permitting requests to use FERC tariffs instead of actual costs for 
determining transportation allowances; and (3) limits on transportation 
allowances. Several industry commenters believed the proposed rules 
discriminate against lessees with affiliated transporters by requiring 
them to use a regulatory cost calculation to determine their 
transportation allowances, whereas third parties are permitted to use 
tariffs.
    MMS Response: In Section III(i) of this preamble, we responded in 
detail to comments about not allowing marketing costs.
    In the final rule, we have eliminated the option for lessees to 
request the use of a FERC tariff in lieu of calculating its actual 
transportation costs in non-arm's-length transportation arrangements. 
Since the 1988 rules were promulgated, FERC has renounced jurisdiction 
over many, if not most, pipelines on the OCS. Oxy Pipeline, Inc., 61 
FERC para. 61,051 (1992); Bonito Pipeline Co., 61 FERC para. 61,050 
(1992), aff'd sub nom., Shell Oil Co. v. FERC, 46 F.3d 1186 (D.C. Cir. 
1995); Ultramar, Inc. v. Gaviota Terminal Co., 80 FERC para. 61,021 
(1997). Those FERC decisions resulted in MMS rejecting use of FERC 
tariffs under the existing rule because FERC cannot ``approve'' a 
tariff over which it has no jurisdiction. This in turn has resulted in 
litigation between several lessees and the Department over the 
applicability and meaning of the existing rule. Shell Offshore, Inc. v. 
Babbitt, No. CV98-0853 (W.D. La. Mar. 17, 1999), appeal pending, Nos. 
99-30532 and 99-30745 (5th Cir.); Torch Operating Co. et al. v. 
Babbitt, Nos. 1:98CV00884 ES and consolidated cases (D.D.C.).
    Absent any possibility of review or check by FERC over the 
reasonableness of the rates filed with FERC for such pipelines, MMS has 
no avenue to assure that the ``tariff'' filed by a pipeline affiliated 
with the lessee is reasonable. The potential for lessees to claim 
excessive transportation allowances in non-arm's-length situations is 
clear. Indeed, in many cases, MMS auditors have found that the FERC 
tariff the lessee has used is considerably higher than the actual costs 
that otherwise would be allowed under the existing rule.
    This contrasts with the situation where a lessee pays an 
unaffiliated pipeline the rate that the pipeline had filed with FERC. 
In that event, the ``tariff'' represents the lessee's actual 
transportation costs because that was what it in fact was charged. 
Thus, in eliminating the FERC tariff exception, lessees are allowed to 
deduct their actual costs in both cases.
    Further, in this final rule MMS has retained the provision that if 
the lessee's actual transportation costs exceed 50 percent of the value 
of the product, the lessee may apply for, and MMS may approve, an 
allowance greater than that amount.
    Summary of Comment--Duplicate Quality Adjustments: One State 
commenter believed that proposed paragraph 206.113(a) permitted 
``double-dipping'' for quality adjustments, since paragraphs 206.112(a) 
and (e) both provide for quality adjustments, thus allowing a double 
deduction for quality for crude oil at the lease and the market center. 
This commenter also noted that because paragraph 206.112(a) allows for 
deduction of a location differential between the lease and the market 
center, and paragraph 206.112(c) allows for deduction of transportation 
costs between the lease and the aggregation point, paragraph 206.113(a) 
will allow the lessee to deduct its transportation costs from the lease 
to the aggregation point twice.
    MMS Response: In this final rule, we added a new paragraph (g) to 
Sec. 206.112 to clarify that you may not use any transportation or 
quality adjustment that duplicates all or part of any other adjustment 
that you use under Sec. 206.112. Moreover, the structure of the final 
rule is not susceptible to the problem the commenter describes. Under 
the final rule, for example, if you dispose of your production under an 
arm's-length exchange agreement, but transport the oil away from the 
lease to an intermediate point before giving it in exchange, you cannot 
claim a transportation allowance between the point where you give the 
oil in exchange and the point you receive oil back in exchange if you 
use a location differential for the segment between those two points. 
This same principle applies for all adjustments addressed in 
Sec. 206.112. That is, any time a lessee takes one of the listed 
adjustments, it cannot duplicate any portion of that adjustment as part 
or all of any other adjustment that otherwise would be allowable.
    Summary of Comment--No Quality Adjustment in Absence of Quality 
Bank: One commenter noted that, in the absence of a quality bank, the 
rule does not provide for any adjustments for quality differences 
between the indexed

[[Page 14046]]

crude oil and the oil produced at the lease.
    MMS Response: In the final rule, MMS intentionally did not include 
a specific quality differential unless there is a quality bank that 
applies to the lessee's production. MMS does not want to be in a 
position of permitting quality adjustments where they may not be 
warranted. Further, quality adjustments will be reflected in the 
location differentials applied by lessees from their arm's-length 
exchange agreements. Finally, MMS has provided, in Sec. 206.112 of the 
final rule, that if the lessee believes it does not have the 
information necessary to calculate a location/quality differential or 
transportation allowance, the lessee may request approval from MMS for 
the location/quality differential or transportation allowance. This may 
provide an opportunity to reflect quality differences the lessee 
believes are not otherwise accounted for.

VII. Responses to Public Comments on July 1998 Proposal

    MMS's July 1998 proposal included several additional proposed 
changes based on comments received on the February 1998 proposal:
    (1) The definition of ``affiliate'' was changed back to its meaning 
under the current rule, but made separate from the ``arm's-length'' 
definition;
    (2) Specific regulatory language was inserted stating that MMS 
would not ``second guess'' lessees' marketing decisions by disallowing 
arm's-length gross proceeds as royalty value; and
    (3) The procedure for valuing production subject to arm's-length 
sale following exchanges was modified. Value would be the arm's-length 
sale price following a single exchange, but where more than one 
exchange is involved, the lessee would have to use index pricing.
    MMS also requested comments on the definition of ``gathering'' as 
related to deepwater leases involving subsea production without a 
platform but with long-distance movement of bulk production.
    We received approximately 200 pages of comments within 25 separate 
submissions. Commenters included 3 States (6 submissions), 4 industry 
trade groups, 12 producers (13 submissions), 1 watchdog group, 1 
concerned citizen, and two members of Congress (1 submission).
    Although MMS asked for specific comments relating to particular 
issues (63 FR 38355), and reiterated that previous comments need not be 
resubmitted because they are already part of the record, there were 
many comments similar to previous submissions. Rather than repeating 
all such issues and comments here, we refer the reader to Sections I, 
III, IV, V, and VI. Instead, with a few exceptions, we address only 
those comments on provisions that are new or revised from the previous 
proposals. The comments fall into 11 topical categories ((a) through 
(k) below). Each topic begins with a description of the issue and is 
followed by a summary of comments and MMS's response.
(a) General Comment
    The issue relates to the overall changes in MMS's July 1998 
proposal.
    Summary of Comments: One commenter believes the latest proposal 
provides numerous concessions to industry and thus amounts to a weaker 
rule.
    MMS Response: We disagree with this comment. None of the changes in 
the July proposal should result in a weaker rule. Rather, they clarify 
the specifics of the rule and make it more usable for all involved. The 
changes result from a reasoned analysis of comments made by all parties 
over this extended rulemaking process. Rather than trying to give a 
specific response to this general comment, we address the proposed 
changes in the July 1988 proposal one-by-one below.
(b) MMS's Proposed Definition of Affiliate
    MMS proposed retaining the meaning of ``affiliate'' embodied in the 
current rules at Sec. 206.101, but removing it from the ``arm's 
length'' definition.
    Summary of Comments: One commenter believed that the 10 percent 
threshold which constitutes no controlling interest in an affiliate is 
too low; at least 20 percent should be used, because this is the 
standard used by the Bureau of Land Management. Most commenters 
believed that the definition of affiliate was too vague, and specific 
criteria for rebutting the presumption of control were needed. One 
commenter believed the burden should be on the lessee to prove that the 
presumption of control is incorrect. One commenter stated that 
transactions between affiliates with any common ownership should not be 
considered arm's length. One commenter believed that by retaining the 
current definition of affiliate, it becomes easier for a company to pay 
on gross proceeds rather than index, which is the proper value.
    MMS Response: See MMS's response in Section VI(a).
    Summary of Comments: One group presented a scenario in which a 
small group of producers bands together to build a pipeline, but if one 
member of the group owns more than a 10 percent interest in the 
pipeline, they may be penalized under the affiliate definition.
    MMS Response: This scenario is unlikely to play out as portrayed. 
Moreover, the definition of ``arm's length'' goes beyond ownership and 
affiliation. The owners also must have opposing economic interests in 
the pipeline to claim arm's-length status. Under this common ownership 
scenario all the owners likely would be deemed non-arm's-length as 
related to the pipeline.
(c) Breach of Duty To Market
    In the July 1998 proposal, MMS tried to allay industry concerns 
about potential additional royalty assessments by 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.
    Summary of Comments: Industry and their representative 
organizations were not reassured that MMS will not ``second-guess'' 
their marketing decisions. Many believed the terms ``substantially 
below'' and ``market value'' were not easily defined and could lead to 
MMS questioning legitimate transactions. One commenter said that MMS 
has in the past 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.
    MMS Response: 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 resided 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.
    We agree with the commenter who said lessees have nothing to fear 
if they are acting in good faith. This provision is simply meant to 
protect royalty value if, for example, a lessee were to inappropriately 
enter into a substantially below-market-value transaction for the 
purpose of reducing royalty.
    In Sec. 206.102(c)(2)(ii) of the final rule, in response to 
comments, we specifically state that MMS will not use this provision to 
simply substitute its judgment of the market value of the oil

[[Page 14047]]

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, 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. Likewise, the fact 
that one co-lessee sells production at the lease while another lessee 
sells its production downstream does not imply that the co-lessee who 
sells at the lease has breached its duty to market.
    Some commenters have argued that adding to the lessee's gross 
proceeds the marketing costs that a purchaser of oil, rather than the 
lessee, incurred constitutes ``second guessing'' of an arm's-length 
contract. They cite as a purported example of such ``second guessing'' 
the IBLA's decision in Amerac Energy Corp., 148 IBLA 82 (1999) (motion 
for reconsideration pending). MMS strongly disagrees with this 
argument. The Amerac case is not an example of ``second-guessing.'' 
Lessees may not avoid the obligation to market production at no cost to 
the lessor by transferring the function to the purchaser and accepting 
a lower price in return. In the Amerac case, neither MMS nor the IBLA 
``second guessed'' the contract at all.
(d) Marketing Fees
    MMS has maintained its ``duty to market'' provision with no 
additional deductions allowed for marketing or other associated costs.
    Summary of Comments: One commenter believes the administrative fee 
that is charged under MMS's existing Small Refiner Royalty-In-Kind 
program is analogous to a marketing fee. Consequently, lessees who use 
index prices should be allowed to deduct marketing fees from these 
prices.
    MMS Response: The fee charged to the small refiners for 
participation in the RIK program covers MMS's additional costs in 
administering the program and does not relate to a marketing fee. The 
MMS fee does not parallel marketing costs incurred by the producers.
(e) Exchanges
    In response to earlier industry comments, MMS proposed in its July 
1998 proposal that where oil was involved in a single exchange before 
an arm's-length sale, its value should be based on the arm's-length 
gross proceeds under that sale. But if there were two or more 
exchanges, the oil would be valued under Sec. 206.103.
    Summary of Comments: Most industry commenters and their 
representative groups still stressed the problem of tracing the oil 
through an exchange to determine proper value. In many cases, the oil 
is commingled with non-Federal oil and sold in bulk, creating 
difficulty in determining the true value of the Federal portion. 
Additionally, there can be a significant workload if any corrections 
need to be made to previously-reported values. The producer should at 
least be given the option of using: (1) the arm's-length sales price 
after the exchange, or (2) index value. One commenter believed that any 
exchange between affiliates should not be considered arm's length, that 
the definition of exchange should be modified to include only exchanges 
that are truly at arm's length, and that the definition of exchange 
should be expanded to include other specific types of exchange 
agreements. Two commenters believe that if a lessee is to use gross 
proceeds after an exchange, then it must report all balancing 
agreements for that lease to the MMS.
    MMS Response: MMS understands the potential administrative burden 
of tracing. We are also well aware of the desire of other producers, as 
expressed in the meetings sponsored by Senator Breaux 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, in this final rule, MMS 
allows 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 RMR, benchmarks). The selected option, once chosen, cannot 
be changed for 2 years and must be applied to all of the lessee's oil 
produced from the same unit, communitization agreement, or lease (if 
the lease is not part of a unit or communitization agreement) that is 
sold at arm's length following one or more exchanges. This process 
preserves the integrity of the rule's underlying principle of applying 
arm's-length gross proceeds where appropriate, but still allowing use 
of index/benchmark values that fairly represent market value where 
``tracing'' would be too burdensome.
    Also, 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 and followed by an arm's-
length sale must be valued at the appropriate index/benchmark value 
under this final rule. We also agree that the definition could be 
clarified by specifying several other types of exchange agreements. We 
have done this in the final rule. We do not believe, however, that it 
is to the lessee's or MMS's benefit for all balancing agreements to be 
reported to MMS. Such agreements should be made available on audit or 
as otherwise requested by MMS.
(f) Binding Guidance
    MMS did not request comment on this issue in its July 1998 
proposal, but drew several comments. The February 1998 proposal stated 
that lessees could petition MMS for non-binding guidance.
    Summary of Comments: MMS received five comments stressing the 
importance of MMS issuing binding guidance. They believed that the 
nature of a business relationship requires it. One commenter believed 
that guidance should not be binding because all of the facts may not be 
available at the time the guidance is issued.
    MMS Response: See Section VI(f) of this preamble for a complete 
discussion of this issue.
(g) Gathering versus Transportation
    MMS asked for comment on whether the definition of transportation 
should include subsea movement of bulk, untreated production over 
distances of 50 miles or more. This typically involves a subsea 
completion and subsequent movement to a platform where the production 
first surfaces and is treated. If this movement is considered 
transportation, the associated costs may be allowable deductions from 
royalty. If the movement is considered gathering, the costs would not 
be allowed.
    Summary of Comments: MMS received mixed comments on this issue. The 
majority of the producers commented that movement away from the lease 
should be considered transportation. Other comments centered on the 
fact that many deepwater leases are already receiving some type of 
royalty relief, and additional deductions are not warranted.
    MMS Response: This issue arose in the public comments for the first 
time in the meetings of July 9 and 22, 1998, sponsored by Senator 
Breaux. In the past, MMS has consistently held that movement of 
production to a central accumulation or treatment point prior to the 
royalty measurement point is considered gathering, rather than 
transportation of marketable production eligible for a deduction from 
royalty. In this final rule, MMS has not changed the existing 
regulatory language. (However, we further note that on May 20, 1999, 
the MMS Associate Director for Royalty Management issued

[[Page 14048]]

guidance regarding movement of production from deepwater leases).
(h) MMS Use of BBB Bond Rate
    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)).
    Summary of Comments: 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. 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.
    MMS Response: We have continued the use of the Standard and Poor's 
BBB industrial bond rate in this final rule. MMS did not propose 
specific provisions regarding the rate of return, but received numerous 
comments on those issues. This issue is discussed more fully below in 
the responses to the comments on the December 1999 proposal in 
paragraph IX(a).
(i) Quality and Transportation Adjustments
    In its February 1998 proposal, MMS allowed quality adjustments in 
Sec. 206.112 based on premia or penalties determined by pipeline 
quality bank specifications at intermediate commingling points, at the 
aggregation point, or at the market center applicable to the lease. 
Allowable transportation deductions were based on actual costs of 
movement, consistent with the rules currently in effect.
    Summary of Comments: Two commenters believe that only gravity and 
sulfur banks should be used for quality adjustments. One commenter 
believes the rule should allow transportation costs only to the nearest 
market center and by the cheapest means to move it there.
    MMS Response: In this final rule, MMS intentionally did not include 
specific quality differentials unless a quality bank applies to the 
lessee's production. MMS does not want to permit quality adjustments 
where they may not be warranted. Further, quality adjustments will be 
reflected in the location differentials applied by lessees from their 
arm's-length exchange agreements and in location differentials that MMS 
provides to lessees upon request under Sec. 206.112(f). In this way, 
MMS is allowing only additional pipeline-specific adjustments where 
they exist.
    Consistent with the current rules, transportation allowances in 
this final rule are based on actual transportation costs. MMS 
historically has not questioned whether the transportation was to the 
nearest market center or whether it was by the cheapest means 
available. We presume that lessees will act prudently to market their 
oil at the appropriate point and use the most efficient means of 
transportation available. Once again, MMS does not intend to ``second-
guess'' marketing decisions to which these factors apply.
(j) Tendering and Other Alternatives
    In its various proposals, MMS generally has not incorporated 
industry-proposed valuation alternatives. An exception is application 
of tendering programs in the RMR.
    Summary of Comments: Many comments from industry and their trade 
groups criticized MMS for not permitting use of viable alternatives 
such as tendering programs in all parts of the U.S. Additionally, MMS 
ignored many lease-based alternatives and the option of taking royalty 
in kind.
    MMS Response: MMS believes it has adequately responded to all 
alternatives presented by industry above. For example, see Section 
VI(d) for detailed comments and responses regarding tendering programs 
and Section III(r) for a discussion of royalty in kind.
(k) Gross Proceeds Valuation
    The various MMS proposals have allowed lessees to use their gross 
proceeds received under arm's-length sales as their royalty value 
basis.
    Summary of Comments: One commenter believes the use of gross 
proceeds as a method of valuation is flawed because it does not always 
represent the full value of the oil. Two commenters state that only 
independents should be allowed to use gross proceeds, while all major 
integrated producers should use index prices.
    MMS Response: MMS's valuation rules have always followed the 
general premise that arm's-length gross proceeds represent market value 
and hence royalty value. However, the various MMS proposals and this 
final rule all include provisions that where an arm's-length sales 
contract does not reflect the total consideration received for the oil, 
MMS may require that the lessee value the oil under the appropriate 
index or benchmark value or at the total consideration received. For 
example, if in return for its oil the lessee received the contract 
sales price plus some other valuable goods or benefits--for example, a 
new car--the total consideration would include the contract price and 
the car's value. Also, we do not believe it is appropriate to apply 
different valuation methodologies based solely on whether the lessee is 
an independent producer or a major integrated company.

VIII. Responses to Public Comments on March 1999 Notice

    On March 4, 1999, in response to requests by Members of Congress 
and parties interested in moving the process forward to publish a final 
rule, the Secretary announced he would reopen the comment period. MMS 
reopened the comment period from March 12, 1999, through April 12, 1999 
(and later extended the comment period through April 27, 1999). The 
Federal Register notice announcing the reopening of the comment period 
(64 FR 12267 (March 12, 1999)) provided the contents of the August 31, 
1998, letter from the Assistant Secretary for Land and Minerals 
Management, to the Senate outlining the direction the final rule might 
take on certain issues. The letter identified seven areas where MMS was 
considering changes in response to commenters' concerns: (1) 
Definitions; (2) valuation of oil sold by the lessee at arm's length; 
(3) valuation of oil sold after arm's-length exchange agreements or 
sold by an affiliate at arm's length; (4) valuation of oil not sold at 
arm's length; (5) location/quality adjustments to index prices; (6) 
transportation allowances; and (7) non-binding valuation guidance.
    The MMS also scheduled three workshops during the comment period 
(Houston, Texas, March 24, 1999; Albuquerque, New Mexico, March 25, 
1999; and Washington, DC, April 7, 1999) to obtain public input on 
specific issues that remained to be resolved.
    MMS received 117 pages of comments from 16 commenters (three State 
agencies, two industry trade associations, eight oil and gas producers, 
two public interest groups, and one congressional office).
    In response to the positions outlined in the August 31, 1998, 
letter to the Senate, industry participants at the workshops submitted 
a set of six unified industry proposals for discussion. These proposals 
were supported by both the major trade associations and the independent 
trade associations and became the primary focus of the workshops. 
Industry's written comments basically reiterated its support for these 
proposals. The States and public interest groups' comments were more 
general in nature and stated an overall objection to the reopening of 
the comment period and discussion of

[[Page 14049]]

the ``same old'' issues. They objected to the continual delays in 
publishing a final rule and recommended that MMS proceed posthaste to a 
final rule based on index pricing. Specific comments by States and 
interest groups are included in the discussion of industry proposals.
(a) Use of Comparable Sales in Non-arm's-length Situations
    Summary of Comments: For non-arm's-length sales, industry 
commenters proposed adoption of a menu of valuation alternatives that 
would center on using a weighted average of comparable arm's-length 
sales transactions at the lease. Under their proposal, a minimum of 20 
percent of the lessee's production must be sold or purchased at arm's-
length, including tendering programs. Other value benchmarks, including 
index, could be used in situations where comparable sales were not 
adequate. Industry advanced this proposal on the theory that it 
reflects the value of production ``at the lease.'' Industry commenters 
also maintained that using comparable sales would be a more accurate 
method of capturing the quality characteristics of lease production and 
it would avoid the complexity of calculating differentials between the 
lease and market center. Companies that tender their production under a 
competitive bidding process expressed strong support for using such 
programs to establish value for royalty purposes.
    States continue to oppose lease-based benchmarks, because they 
believe arm's-length sales at the lease are limited, and they have 
concerns about the use of tendering programs. One State commenter 
stated that the comparable sales approach does not address the problem 
of undervalued field prices. That commenter plus an interest group 
recommended that MMS consider going forward with a rule specific to 
majors.
    MMS Response: In the final rule, 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 RMR, 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 a better indicator of the value of 
production and are preferable to attempting to use 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.
    The RMR, where reliable spot prices are not readily available, is 
an exception. About two-thirds of crude oil produced there is sold at 
arm's length, and there is not a reliable index price in that region. 
In addition, industry's proposal has substantial practical difficulties 
since companies are not privy to other companies' ``comparable'' sales 
transactions, and to the extent that such information may be available 
to MMS, it is unaudited for current periods. The final rule thus 
primarily uses index prices, adjusted for location and quality, to 
establish value for oil not sold at arm's length.
(b) Binding Valuation Determinations
    Summary of Comments: Industry commenters 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. 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.
    State commenters expressed general opposition to binding 
determinations, stating that information could be inaccurate, 
incomplete, or dated and that MMS should have discretion over issuing 
any binding 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.
    MMS Response: See Section VI(f) above and the explanation of 
Sec. 206.107 of the final rule in Section X below.
(c) Transportation Allowances in Non-Arm's-length Situations
    Summary 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 the 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 Standard & Poor's BBB bond rate. Undepreciated capital 
investment would never be less than 10 percent of the original capital 
cost.
    Industry commenters argued that they only agreed to the MMS actual-
cost method under the 1988 regulations because of the provision to use 
FERC tariffs. They oppose MMS proposing to revoke use of tariffs 
without allowing an adequate transportation allowance rate that 
reflects the value of the production at the market centers. They also 
assert that the transportation allowance rate should recognize the risk 
associated with building pipelines. Furthermore, they point out that 
the current rate of return based on one times BBB is too low to 
accurately reflect a company's cost of capital.
    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 Response: As explained elsewhere in this preamble, in the final 
rule MMS has deleted the FERC tariff exception. However, we note that 
independently of eliminating the FERC tariff exception, MMS has 
modified several provisions related to non-arm's-length transportation 
allowances, including new depreciation schedules if a transportation 
facility is sold, and a ``base'' investment level to which the rate of 
return could always be applied, as discussed further below. In the 
final rule, we have continued the use of the Standard and Poor's BBB 
industrial bond rate, for reasons discussed more fully below in the 
responses to the comments on the December 1999 proposal at paragraph 
IX(a).

[[Page 14050]]

(d) Adjustments to Downstream Values
    Summary of Comments: Industry commenters stated that they would not 
be properly compensated for location and quality adjustments under the 
proposed rule. They contended that, with valuation being set downstream 
of the lease (i.e., index prices), the prescribed location and quality 
adjustments do not arrive at a proper value at the lease, and they do 
not adequately compensate the lessee for the costs and risks associated 
with those midstream and downstream activities. They claimed that use 
of Form MMS-4415 would be unduly burdensome and too out-of-date for 
providing accurate location and quality adjustments to current index 
prices. They proposed alternatively that industry and MMS jointly 
develop a uniform monthly report or contemporaneous tables by region 
incorporating differentials reflective of actual recent market 
conditions. They also proposed adjustments for marketing activities.
    MMS Response: MMS has always proposed that all reasonable location 
and quality adjustments be applied to the appropriate index, and 
believes this final rule permits those adjustments. Under Sec. 206.112, 
the lessee may request approval from MMS for additional or alternative 
adjustments if necessary. However, for reasons explained in Section 
III(i), MMS maintains that marketing costs are not a proper deduction 
from royalty value and has retained this provision in the final rule.
    Under the final rule, MMS will not publish location/quality 
differentials because MMS believes that lessees generally will 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. As a result of eliminating MMS-published differentials, the 
proposed Form MMS-4415 is not part of the final rule. Because MMS is 
not requiring the proposed form, it is not necessary to address the 
extensive comments MMS received regarding the content and timing of the 
form.
    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 will have the necessary information regarding actual 
transportation costs to claim the appropriate transportation allowance.
(e) Definition of Affiliate
    Summary of Comments: Industry commenters did not object to having 
separate definitions for ``affiliate'' and ``arm's-length,'' and in 
general, did not oppose the provision that ownership of 10 through 50 
percent creates a presumption of control, as reinstituted in the July 
1998 proposal. However, they recommended certain guidelines for lessees 
to rebut the presumption of control. If the lessee meets any of the 
following four criteria, they would be deemed to have no control over 
the affiliate: (1) The affiliated entity can take any relevant action 
without an affirmative vote of the lessee; (2) the lessee is not a 
general partner of a partnership; (3) the lessee is a natural person 
not related within the fourth degree to the affiliated natural person; 
and (4) the lessee's directors on the board of the affiliated company 
cannot block any relevant action of the affiliated company. Industry 
commenters also asserted that a lack of opposing economic interests 
cannot be assumed. However, they believe that if noncontrol is 
demonstrated, the existence of ``opposing economic interests'' has been 
established. One industry commenter indicated that MMS should bear the 
burden of proof in demonstrating a lack of opposing economic interest.
    A public interest group commenter suggested that any economic 
interest in the other company should require index-based valuation. A 
State commenter suggested that ownership percentages should be only one 
of many factors to determine whether a contract is arm's-length and 
that any list of control rebuttal factors should be illustrative only.
    MMS Response: See MMS response in Section VI(a).
(f) ``Second-guessing''
    Summary of Comments: As stated above, industry commenters expressed 
significant concern that the additional regulatory language proposed in 
the July 1998 proposal at paragraph 206.102(c)(2)(ii) would lead to 
further uncertainty and misunderstanding regarding the lessee's duty to 
market production in arm's-length situations. Industry reiterated these 
concerns at the workshops. Particularly, they 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 themselves and the unaffiliated companies.
    MMS Response: See Section VII(c) above.

IX. Responses to Public Comments on December 1999 Proposal

    On December 30, 1999, MMS published a reproposal of the entire 
rule. The December 1999 proposal modified the prior proposals in a few 
respects, specifically:
     MMS proposed to eliminate MMS-published location/quality 
differentials, and, as a consequence, proposed to eliminate the 
previously-proposed Form MMS-4415.
     MMS proposed to permit a continuing return on investment 
component of the transportation allowance, even after a pipeline is 
fully depreciated, and to permit a new depreciation schedule when a 
lessee buys a pipeline at arm's length under certain conditions.
     MMS asked for comments on alternative rates of return, 
including multiples of the Standard & Poor's BBB bond rate and weighted 
average cost of capital methods.
     MMS proposed to change the definition of ``affiliate'' in 
light of the D.C. Circuit's decision in National Mining Association v. 
Department of the Interior, 177 F.3d 1 (D.C. Cir. 1999).
     MMS proposed value determinations issued by the Assistant 
Secretary for Land and Minerals Management that would be binding on 
both MMS and the lessee, and value determinations issued by MMS that 
would be binding on MMS and not the lessee.
     MMS proposed specific regulatory language regarding so-
called ``second guessing'' of arm's-length sale prices.
    MMS received approximately 700 pages of comments on the December 
1999 proposal. In addition, MMS conducted public workshops in Denver, 
Colorado, on January 18, 2000, in Houston, Texas, on January 19, 2000, 
and in Washington, D.C. on January 20, 2000. The comments divide into 
41 categories, addressed in (a) through (aj) below.
    (a) MMS Should Modify the Rate of Return in Calculating Actual

[[Page 14051]]

Transportation Costs Allowances and Involve FERC.
    Summary of Comments: Many industry comments favored increasing the 
rate of return in some fashion. Some suggested increasing the rate used 
in calculating the allowance to twice the Standard and Poor's BBB 
industrial bond rate. In some cases, industry provided detailed reports 
and analyses to support their claims.
    Three States and an individual commented that increasing the rate 
of return above the BBB rate is unnecessary. They favor maintaining the 
provisions in the current regulations. The individual stated that the 
BBB rate already is for marginal credit risks and already is enhanced, 
hence a higher return is unneeded.
    Several U.S. Senators encouraged MMS to utilize the expertise of 
FERC staff to develop costs of debt and equity applicable to pipeline 
investments for use in establishing a rate of return for lessees to use 
in calculating actual transportation costs for non-arm's-length 
transportation arrangements.
    MMS Response: The fact that a lessee's overall operations are 
funded historically by some proportion of debt and equity does not 
imply that the resulting aggregate weighted average cost is appropriate 
for determining a proper transportation allowance for royalty purposes. 
Different projects and investments will be expected to involve very 
different levels of risk and generate different levels of returns. They 
also may be funded in different ways. For example, a pipeline 
investment likely would be much less risky than investment in a wildcat 
drilling operation and thereby command a lower rate of return.
    MMS expects that lessees will finance pipeline investments in the 
least costly manner available. MMS's research indicates that most 
recent pipeline investments are financed largely through debt rather 
than equity. For those pipelines financed entirely by debt, the BBB 
bond rate is a very favorable rate to claim as a cost for the lessee, 
because most large operators can borrow money at lower rates. Also, 
equity financing is typically more costly than debt financing.
    The Standard & Poor's BBB industrial bond rate (BBB rate) that MMS 
currently uses typically falls between the cost of borrowing for large 
integrated oil and gas companies and the return that these firms are 
expected to earn on their capital investments. Therefore, given the 
predominance of debt financing for pipeline investments, MMS believes 
the choice of the BBB rate for the cost of capital is entirely 
reasonable.
    The industry proposes using a weighted average cost of capital. 
Industry states that this weighted average cost is approximately 2.2 
times the BBB bond rate. That is the basis of industry's proposal to 
use 2 times the BBB rate in transportation allowance calculations.
    However, MMS believes that the companies used in industry's 
weighted average cost of capital calculation (those in Standard 
Industrial Classification (SIC) code 131) are less representative of 
lessees that typically build or own pipelines (including through 
affiliate arrangements) than those listed in SIC code 291. We believe 
code 291 is more appropriate because it includes major integrated 
firms, and therefore more closely represents the body of companies that 
typically would be involved in owning or constructing pipelines.
    Also, we agree with industry's proposal to calculate a before-tax 
rate of return. Royalties are calculated before tax, so the rate of 
return used should be a before-tax rate as well. However, in adjusting 
certain after-tax information to obtain before-tax estimates, we did 
not use the 35 percent marginal tax rate used by industry. Instead, we 
used the 19 percent average tax rate that we find find is more 
appropriate for SIC code 291 firms.
    Industry's calculation of weighted cost of capital is further 
exaggerated because it uses the BBB rate as the debt rate. As explained 
above, we believe that the BBB rate generally is higher than these 
companies' actual borrowing rates would be.
    Further, we believe the equity rate used in industry's calculations 
was not appropriate because the equity rate applicable to companies in 
SIC code 131 is higher than the equity rate for companies in SIC code 
291.
    Even if, arguendo, we accepted the premise of using a weighted 
average cost of capital as the rate of return, MMS has found, using 
more appropriate SIC codes, tax rates, debt rates, and equity rates, 
that the average cost of capital is much lower than the 2.2 times BBB 
that industry calculated. MMS therefore concluded that industry's 
proposal is not well founded. MMS concludes that the BBB bond rate is 
an appropriate rate of return, and we have retained it in the final 
rule. We also conclude that since the BBB bond rate is adequate as a 
rate of return used in calculating actual transportation costs for 
royalty purposes, there is no need for MMS to utilize the expertise of 
FERC staff to develop costs of debt and equity.
(b) Rulemaking Process
    Summary of Comments: One State commented that it would like to be 
involved in valuation requirements that affect it. Further, the rule 
should include a provision that the affected State may review valuation 
determinations.
    A private organization questioned the rulemaking process in light 
of certain payments made to Department officials from proceeds paid to 
relators as a result of settling certain litigation brought under the 
qui tam provisions of the False Claims Act. It urges a delay in the 
rule until all matters associated with these payments are fully 
examined.
    MMS Response: We understand the importance of the royalty income 
for each State and the fact that valuation decisions affect royalty 
revenues that are shared with States. States already have a major role 
in the process, through delegations of audit authority under 30 U.S.C. 
1735, many informal consultations, and comments on proposed rules such 
as the comments submitted in this instance. We intend to continue this 
cooperative relationship. However, valuation determinations ultimately 
are MMS's responsibility.
    The payments made to a Department employee from litigation 
settlement proceeds are the subject of a pending investigation. In that 
respect, MMS knows of no grounds for delaying this rulemaking.
(c) ``Second Guessing''
    Summary of Comments: An industry comment stressed support for the 
concept of MMS not ``second guessing'' industry's decisions in 
disposing of crude oil production. However, the commenter would like to 
see the concept expanded in the preamble and the associated sections 
within the rule itself.
    MMS Response: MMS continues to reiterate that it will not ``second 
guess'' a company's decision on how it disposes of production. We have 
emphasized this at several points, both in the text of the rule and in 
the preambles to this rule and previous proposals. We do not believe 
that additional discussion would be helpful. As discussed above, MMS 
has rarely, if ever, ``second guessed'' the value received in an arm's-
length sale of oil, so we cannot use actual experience that would 
provide a basis for elaboration.
(d) Spot Prices as a Marker of Value
    Summary of Comments: Several industry commenters reiterated the 
assertion that spot prices do not reflect lease values even after 
adjusting for

[[Page 14052]]

quality and location. MMS fails to provide any analysis showing that 
spot prices do reflect lease value. The use of these prices inflates 
the actual value of the production at the lease, in violation of the 
lease terms.
    Further, some industry commenters questioned the use of the Alaska 
North Slope (ANS) spot price as a marker for west coast oil. The State 
of California reiterated its belief that ANS prices are a valid measure 
of value.
    MMS Response: MMS addressed the use of spot prices previously. The 
comment here was a prominent theme of the comments on the February 1998 
proposal. See Section VI(e) above.
    MMS continues to believe ANS is a valid measure of value for west 
coast production. However, there is language in the rule allowing 
review and changes should an index price become invalid.
(e) Nearest Spot Prices
    Summary of Comments: Some comments from industry urged that if MMS 
is going to use index pricing, lessees should have the option of using 
a more distant index price if that index better reflects sales of oil 
more similar in quality to the lessee's Federal production, or if that 
index better reflects the location specified in the lessee's exchange 
agreements.
    MMS Response: MMS's intent in the December 1999 proposal and this 
final rule in requiring lessees to use index prices at the market 
center nearest the lease is to correlate both proximity to the lease 
and quality similarity. If lessees could choose other market centers, 
the rule would become ambiguous and more vulnerable to manipulation.
(f) Unclear Whether Spot Price Applies to Trading Month or Calendar 
Month
    Summary of Comments: Several industry commenters were not sure if 
the spot price to be used under the rule means the price that applies 
to the trading month or to the production month. They would like to see 
a clarifying example.
    MMS Response: The final rule and this preamble clarify that the 
spot prices to be used in index value calculations are the prices for 
the trading month concurrent with the production month. The term 
``trading month'' is a defined term in the final rule, and means the 
period during which crude oil trading occurs and spot prices are 
determined, generally for deliveries of production in the following 
calendar month.
    In effect, the spot prices used will be the prices published during 
the production month for ANS crude, and prices published principally 
during the production month for other indexes. For example, a 
publication may publish prices between approximately the 26th day of 
month one and the 25th day of month two. That period will be the 
trading month, and the spot prices published in that trading month will 
be used to value, for royalty purposes, production from a Federal lease 
in month two).
    Thus, continuing the example, if the production month is June and 
the oil is produced outside California/Alaska, and the trading month is 
May 26-June 25, you would compute the average of the daily mean prices 
using the daily spot prices published in the appropriate MMS-approved 
publication for all the business days between May 26 and June 25 (for 
delivery in July).
    As indicated previously in this preamble, in the final rule we have 
adopted the index timing method proposed in the January 1997 proposal 
and not the method proposed in February 1998 and December 1999.
(g) Tendering Should Be an Option for Oil Not Traded at Arm's Length
    Summary of Comments: Several comments from both industry and a 
group of U.S. Senators indicated that tendering should be used as a 
valuation methodology in all areas of the country, not just as a 
benchmark in the RMR. Further, MMS restrictions on tendering in the RMR 
are too severe. MMS can ease its restrictions and still prevent 
``gaming''.
    MMS Response: MMS addressed the overall appropriateness of 
tendering programs when similar comments were raised in response to the 
February 1998 proposal.
(h) Use of FERC tariffs in Lieu of Actual Costs
    Summary of Comments: Again, industry submitted numerous comments 
supporting the position that FERC tariffs should be permitted as 
allowances because they recognize the real cost structure of pipeline 
investments; MMS allowances do not recognize these costs. Several State 
comments indicated that FERC tariffs are not appropriate and should not 
be used as allowances.
    MMS Response: MMS addressed the appropriateness of FERC tariffs as 
allowances in the February 1998 responses to public comments.
(i) The Two-Year Election Requirement
    Summary of Comments: Several comments from industry expressed 
concern that the requirement that a lessee declare for a 2-year period 
whether it will use gross proceeds or index pricing is too severe. 
Further, MMS should allow the election on a lease-by-lease basis rather 
than for all production and in intervals less than 2 years.
    A State commented that it generally favors the 2-year valuation 
election as a method to ensure that industry does not ``game'' the 
valuation methods.
    MMS Response: MMS agrees with the State comment that 2 years is 
needed to ensure that lessees do not have any incentive to ``game'' 
valuation methods. However, MMS acknowledges that it may be problematic 
for a lessee to have to declare an overall valuation method for all of 
its properties when circumstances may dictate different approaches for 
properties that are widely geographically separated or from which 
production is marketed in different ways. Therefore, in the final rule, 
MMS is requiring lessees to make the 2-year election on a property-by-
property basis, i.e., for a unit, communitization agreement, or lease 
(if the lease is not part of a unit or communitization agreement).
(j) MMS Ignores Alternative Valuation Methodologies for Non-Arm's-
Length Transactions
    Summary of Comments: A consultant hired by industry claims that MMS 
has not addressed all of the alternatives that can arrive at lease 
value. It has not explained why RIK will not work in all circumstances. 
Other comments asserted that MMS would be able to eliminate valuation 
problems if it were to take its royalty in kind. Most States favor the 
approach of using index prices. One State is open to tendering if a 
lessee can demonstrate that its program will establish competitive 
prices.
    MMS Response: MMS consulted with crude oil experts in economics, 
marketing, and related areas in the formulation of these rules. It has 
consulted with industry, States, and other interested parties for more 
than 4 years. During this time MMS held workshops addressing alternate 
proposals from these parties and made numerous refinements and 
revisions to its proposals. MMS has addressed alternate valuation 
proposals in the sections addressing comments received on earlier 
proposals before the December 30, 1999 proposal.
    It is not incumbent on MMS to prove that RIK will not work in all 
circumstances before issuing a final rulemaking on oil valuation. The 
statutes and lease terms give MMS the option of taking royalty in value 
or in kind. As a steward of publicly owned resources, MMS is 
responsible for

[[Page 14053]]

receiving fair value for development of publicly-owned resources.
(k) MMS Has Not Fully Considered the Advantages of a Lease-Based 
Comparable Sales Valuation Methodology
    Summary of Comments: Industry commenters still embrace comparable 
lease-based arm's-length sales to value production not sold at arm's 
length and claim that their consultants' work demonstrates that there 
are viable markets at the lease.
    MMS Response: MMS has addressed the concept of comparable sales in 
multiple workshops attended by State and industry representatives and 
in sections containing responses to previously submitted comments in 
this rulemaking process. In support of their position, industry 
commenters offer the analyses prepared by Joseph Kalt (Kalt) and 
Kenneth Grant (Grant). For the west coast market, industry includes the 
comments of Samual Van Vactor. In support of their position, Kalt and 
Grant cite an extensive data base of lease-based arm's-length 
transactions that they say demonstrate that a market exists at the 
lease. We are aware that this database apparently exists because Kalt 
cited it in support of industry's position in a presentation to a 
congressional subcommittee reviewing this rulemaking process.
    MMS also understands that this same database has been cited in 
several judicial proceedings where royalty payments were valued at 
posted prices. MMS has not seen the database containing these 
transactions because it was not provided with the comments submitted by 
Kalt and Grant. MMS has no way of verifying whether this database is 
accurate or whether or to what extent it supports Kalt's and Grant's 
thesis. We have no way of knowing whether the database includes 
transactions that MMS would not regard as arm's-length sales, whether 
it includes buy/sell exchanges within arm's-length sales, or whether it 
may involve other possible problems. It is also unclear whether any 
double counting of information may have occurred, since multiple 
parties' sales and purchase information apparently are contained in the 
database.
    MMS cannot rely on data it has not seen and has not examined. MMS 
does not believe that industry has provided convincing evidence or 
analysis to show that a competitive market exists at the lease 
throughout the domain of Federal leases.
    Another consultant hired by industry, Samuel Van Vactor (Van 
Vactor), claims that ANS spot prices are poor indicators for the market 
value of California crude oil. In support of his position, Van Vactor 
cites several difficulties in comparing ANS crude to California crude 
oils.
     ANS is of better physical quality than most California 
crude oil.
     Line 63 spot prices of California crude yield lower values 
than ANS.
     Gravity schedules on posted price bulletins and pipeline 
gravity banks are not intended to make comparisons between crude oils 
from different fields.
     MMS's method is more cumbersome than industry's comparable 
sales method.
     MMS disagrees with Van Vactor's position and reasons. 
While the quality of ANS is clearly different than most Federal 
California crude oil, after adjustments are made for gravity, sulfur, 
and location, it is a good proxy in valuing oil not sold at arm's 
length. ANS spot prices have the advantage of regular transactions of 
sufficient liquidity to establish a fair market price. Spot prices for 
Kern River crude and Line 63 are suspect indicators of market value 
because they reflect only thinly traded volumes. Additionally, Line 63 
is a blend of heavy and lighter crude oil and, when refined, yields a 
different product slate than ANS and other California crude oils.
    Van Vactor's criticism of the use of posted price gravity schedules 
and pipeline gravity banks for making adjustments between different 
fields ignores their common use by industry in exchange contracts 
involving different quality crude oils from distant locations. See 
Review of Selected Technical Reports on MMS's Proposed Federal Oil Rule 
and Supplemental Rule, prepared by Innovation and Information 
Consultants, Inc., dated September 25, 1997, p. 5. That review 
observes:

    Finally, Van Vactor argues that one cannot apply the California 
gravity price differential as a quality adjustment to ANS. He claims 
such adjustments are only meant to measure small deviations around 
the gravity actually being delivered and are not intended to be 
applied across crude fields or to compare with different crude oils. 
He also claims that when comparing ANS with California crudes of 
identical quality, ANS sells for $0.50 to $1.00 per barrel more. We 
disagree with his reasoning and its factual basis. First, it can be 
demonstrated that the interfield (the gravity adjustment factor 
across different fields) and the intrafield (the adjustment factor 
used in posted price bulletins to adjust for gravity variations 
within a field) gravity price differential are very nearly the same. 
[Citing ``West Coast Crude Oil Pricing,'' Department of Energy, 
1988.] Second, the oil companies regularly apply the gravity price 
differential (GPD) on exchange agreements covering many different 
crude oil types, gravity levels and fields within and outside 
California. Indeed even when companies are trading ANS for 
California crude oils, they often apply the California gravity price 
differential (or something lower) to adjust for differences in 
quality. Third, pipelines such as the All America pipeline which 
transports both ANS and California crude oils (heavy and light) 
utilizes a gravity bank that is very similar to the California 
posted price gravity differential. Furthermore, this bank can be 
applied to widely varying gravities (10-30 deg. API).

Id.
    On at least one occasion involving a gravity bank dispute between 
producers of ANS crude oil, an integrated company argued for the use of 
California posted price gravity schedules in making adjustments between 
different grades of ANS crude that was shipped via the Trans-Alaska 
Pipeline. See, Prepared Direct Testimony of Karl Richard Pavlovic, 
dated January 11, 1998, in Exxon USA, Inc. v. Amerada Hess Pipeline 
Corp., Docket No. OR96-14-000 before the Federal Energy Regulatory 
Commission. In short, Van Vactor's arguments against the use of ANS for 
valuing California Federal crude oil are at odds with actual industry 
practices. Additionally, ANS prices are transparent and adjustments for 
location and quality can be made that will provide a value at Federal 
leases for royalty purposes.
    Finally, MMS disagrees with Van Vactor's claim that the ANS 
methodology is more cumbersome than a comparable sales method. A 
comparable sales method would be burdensome for both MMS and industry. 
In many instances companies would not have sufficient transaction 
information to arrive at a reasoned calculation of value. Under the 
current regulations, comparable sales methods (i.e., the benchmarks) 
lead to a significant audit burden for both industry and MMS. Moreover, 
MMS does not believe that in most instances in California there are 
sufficient arm's-length sales at the lease to derive an accurate 
comparable sales value.
(l) Posted Prices are Valid Indicators of Value for Non-Arm's-Length 
Transactions
    Summary of Comments: Some industry commenters continue to assert 
that postings represent market value at the lease. They cite the recent 
jury decision in the Long Beach II trial [i.e., the Exxon case] as 
evidence for this position.
    MMS Response: In the various proposals that have resulted in this 
final rule, MMS has discussed at great length the reasons why we 
believe posted prices no longer represent market value. The reasons why 
the jury's decision in

[[Page 14054]]

the Exxon matter does not imply that posted prices are a valid 
indicator of value, and why it is not contrary to this rule, are 
covered in detail in Section X of this preamble in the discussion of 
the provisions of Sec. 206.103.
(m) MMS Treats Producers Inequitably by Not Allowing Arm's-Length 
Production To Be Valued at Index
    Summary of Comments: MMS received several comments that lessees 
should be allowed to use index pricing where tracing of arm's-length 
dispositions would prove overly burdensome. Others commented that MMS 
should provide the option to value all arm's-length production under 
index pricing.
    MMS Response: The principle that gross proceeds is the primary 
measure of value in arm's-length transactions has been retained under 
these regulations. This means that a lessee must be able to account for 
actual receipts under an arm's-length contract. This is consistent with 
the principle that arm's-length contracts should be the basis for 
valuation whenever possible.
    In the final rule, as in the December 1999 proposal, and for the 
reasons explained in that proposal, MMS has provided the option for 
lessees to choose to report and pay on index values only after one or 
more arm's-length exchanges or after sales to an affiliate. We do not 
believe that use of index prices when production initially has been 
sold at arm's length should be expanded.
(n) Use of Alternate Index Prices
    Summary of Comments: There were some industry comments suggesting 
that MMS use Line 63 and Kern River Spot prices in place of ANS. 
Several comments suggest using index prices from more distant markets 
if the crude oil indexed better approximates quality parameters than a 
nearby indexed crude oil.
    MMS Response: MMS does not believe that the Line 63 and Kern River 
spot prices are dependable indicators of market value for reasons 
explained elsewhere in this preamble. We also have explained elsewhere 
why we do not believe that as a general rule lessees should be allowed 
to use index prices from more distant markets.
(o) Use of Benchmarks Outside the Rocky Mountain Region
    Summary of Comments: Industry commented that the benchmarks 
applicable to the RMR should apply everywhere. The RMR benchmarks 
should be a menu and not a hierarchy, and MMS should modify them to 
allow lessees to use either tracing or index pricing where tendering 
programs do not meet MMS standards. The RMR benchmark that uses a 
volume-weighted average of sales prices must also include adjustments 
for gravity. Also, MMS has not explained why comparable sales are used 
in the proposed Indian rule but not in the Federal rule.
    MMS Response: MMS has addressed the need for a series of benchmarks 
for the RMR in earlier parts of this preamble and in earlier versions 
of this rulemaking. The reasons for prescribing in the final rule an 
initial benchmark, followed by a choice between two other benchmarks if 
the first does not apply, have been explained elsewhere in this 
preamble. In other parts of the country, reliable index prices exist. 
MMS has addressed the concern about gravity differences in the RMR 
comparable sales methodology by requiring that gravity be normalized 
before a volume-weighted average of prices is considered.
    The proposed Indian oil value rule does not include comparable 
sales as the commenters here imply. The ``major portion'' provisions in 
Indian leases are not what the commenters in this rulemaking have 
suggested.
(p) Binding Value Determinations
    Summary of Comments: Several U.S. Senators stated that MMS should 
issue binding value determinations that are appealable 
administratively. (In light of the text of the December 1999 proposal, 
it appears that the congressional commenters are suggesting that MMS, 
and not just the Assistant Secretary, should issue value determinations 
that are binding on the lessee as well as on MMS.) Industry wants MMS 
to broaden the kinds of binding determinations it provides, and then 
only prospectively. These determinations should be issued expeditiously 
and be appealable. The limits on determinations are overly restrictive. 
Fact-specific determinations should be issued. The uncertainty 
surrounding determinations makes the rule unworkable. MMS should expand 
the circumstances in which lessees may receive determinations.
    MMS Response: The final rule provides that MMS will be bound by MMS 
determinations, and that both MMS and the lessee will be bound by 
Assistant Secretary determinations. MMS disagrees with the suggestion 
that value determinations by MMS should be appealable administratively, 
because they are not binding on lessees. We see no need to expand the 
number of potential administrative appeals when enforcement of the 
measure of value in an MMS determination (should the lessee disagree 
with and not follow it) depends on whether MMS later issues an order to 
pay.
    We disagree that the scope of value determinations is overly 
restrictive and we do not agree that MMS should be required to issue 
value determinations in every case in which a lessee asks for one. 
Issuing value determinations is not always appropriate, and MMS must 
retain discretion in this respect. We also do not believe that there is 
``uncertainty'' surrounding determinations or that the procedure in the 
December 1999 proposal and this final rule is ``unworkable.''
(q) Binding Determinations--Allegedly ``Penalizing'' Lessees
    Summary of Comments: Some commenters argued that the provision 
about not penalizing a lessee for failing to follow a value 
determination by MMS is illusory and amounts to a form of ``Hobson's 
choice.'' The commenters say that to require lessees to subject 
themselves to penalties in order to challenge determinations they 
disagree with is unsound policy. MMS should apply the principle that 
the mere existence of a higher selling price does not mean that MMS 
will question the validity of the proceeds in any transaction.
    MMS Response: MMS does not agree with this characterization of the 
value determination process. If a lessee disagrees with a determination 
by MMS, it has the option of not following the determination. The 
burden will lie with MMS to issue an order to pay on the value basis 
contained in the determination. The lessee is not in any different 
position than in any other circumstance in which it may disagree with 
MMS's position on a valuation issue. We are unable to see how this in 
any way ``penalizes'' the lessee or imposes on it a ``Hobson's 
choice.''
    Finally, as explained elsewhere in this preamble, the existence of 
a higher selling price does not in itself imply that the lessee has 
breached its duty to market or that the arm's-length gross proceeds 
would not be accepted as royalty value.
(r) Requirement To Identify Other Lessees When Requesting a Value 
Determination.
    Summary of Comments: At least one commenter argued that the 
requirement in the December 1999 proposal that a lessee must identify 
record title or operating rights owners when requesting a valuation 
determination is unnecessary.
    MMS Response: MMS believes it is appropriate to require lessees to 
identify

[[Page 14055]]

other operating rights owners or record title owners to the extent that 
the lessee knows who they are because they may be affected by the 
analysis or conclusions of a value determination in a manner similar to 
the lessee who requested it. If production for which those other 
parties may be liable for royalty payments is affected by the results 
of a value determination, MMS needs to have this information to proceed 
expeditiously.
(s) Clarification of Value Determination Procedures
    Summary of Comments: At least one commenter suggested that MMS 
should issue guidelines in the rule to help lessees determine if their 
transactions are at arm's length. The commenter argued that the final 
rule should better clarify what decisions do and do not come under the 
valuation determination process.
    MMS Response: With the change made in the definition of affiliate, 
we believe the final rule provides sufficient criteria to determine 
what transactions are at arm's length in the vast majority of 
situations. The final rule at Sec. 206.107 explains that MMS will not 
provide valuation determinations in response to requests for guidance 
on hypothetical situations or matters that are the subject of pending 
litigation or administrative appeals.
    We also removed the provision in the December 1999 proposal that we 
would not provide valuation determinations where the request dealt with 
matters ``inherently factual'' in nature. We proposed not to address 
such requests because the purpose of providing valuation determinations 
is to take given facts and render an interpretation of how they should 
be applied in a given situation, not to interpret what the actual facts 
are. But since the term ``inherently factual'' may mean different 
things to different people and cannot be precisely defined for purposes 
of this rule, we removed this provision in the final rule. We still do 
not intend, however, that valuation determinations would be given just 
to determine the facts involved in a given situation.
    Further, we did not include in this final rule the provision in the 
current rule at Sec. 206.102(g) that the lessee may use its proposed 
value for royalty payment purposes until MMS provides a value 
determination. MMS does not want to be in the position of having to 
accept royalty payment on a value it may find unacceptable, no matter 
how short the period may be between the lessee's request for a value 
determination and MMS's response. MMS will act as expeditiously as 
possible on such requests, but sometimes policy interpretations may be 
required or other complications may arise.
    This preamble at Section VI(f) also explains some types of 
situations where value determinations may or may not be appropriate. 
Value determinations are issued only under Sec. 206.107, in response to 
a specific request for a value determination. An example might be where 
the lessee operates in the RMR and approaches MMS for approval to use 
results from its tendering program to value its production that is not 
sold at arm's length. Or, if the lessee has no tendering program, it 
might ask MMS to determine whether purchases and sales by it and its 
affiliate are at arm's length and of sufficient quantities to permit 
use of the second RMR benchmark. Requests not covered under 
Sec. 206.107 include, for example, those under the fourth benchmark for 
the RMR where the Director establishes an alternative valuation method 
(Sec. 206.103(b)(5)), calculation of a value at the refinery when the 
adjusted index price yields an unreasonable value (Sec. 206.103(e)), 
and calculation of a location/quality differential when the lessee does 
not have its own information to calculate the differential 
(Sec. 206.112(f)). MMS will respond to these requests, but they will 
not be handled under the value determination procedures.
(t) Timely Value Determinations
    Summary of Comments: Some commenters express a lack of confidence 
that MMS will be able to issue timely determinations. They say that MMS 
should rule on all issues and provide timely answers, even if a 
negative decision results. The States are concerned about MMS making 
decisions based on incomplete information.
    MMS Response: MMS has identified some types of matters for which 
value determinations probably are not appropriate, such as hypothetical 
situations or matters that are the subject of pending litigation or 
administrative appeals. It is in MMS's interest to expedite value 
determinations so as to resolve as many matters as possible and avoid a 
backlog. (See also our response at (s) immediately above.) As for the 
States' concern that MMS will make decisions based on incomplete 
information, MMS does not intend to make a determination until the 
lessee provides all the pertinent facts, documents, and analysis. In 
the rare event that a misstatement or omission of the material facts 
occurs, or the facts ultimately developed are materially different from 
the facts on which the guidance was based, MMS could change the 
determination retroactively.
(u) State Involvement in MMS Value Determinations
    Summary of Comments: State commenters said they would like to be 
involved in the decision-making process when binding determinations 
affect their revenue. California is concerned with lessees possibly 
requesting valuation determinations on no more grounds than an asserted 
belief that a methodology required under the rule is not applicable. 
The State commenters argued that prospective valuation determinations 
should ``sunset'' after 2 years, within which time the lessee must 
demonstrate that the circumstances continue to apply.
    MMS Response: MMS is mindful of States' concerns in valuation 
issues. As a general practice, MMS consults with States in preparing 
valuation determinations, but the ultimate decisions with respect to 
value determination requests rest with MMS and the Assistant Secretary. 
MMS does not believe that lessees have any incentive to file spurious 
or unsupported requests for value determinations. If MMS receives a 
spurious or frivolous request, it will be rejected. (Such a situation 
would be another example of an appropriate circumstance in which MMS 
would decline to issue a determination.) MMS does not believe it is 
appropriate to include a ``sunset'' provision in every determination as 
a matter of course. However, MMS may include such a provision where 
circumstances indicate that the situation addressed in the 
determination is likely to change, or that the matter should be 
reexamined after some interval.
(v) Location and Quality Differentials
    Summary of Comments: Industry commenters uniformly favor removing 
the requirement to submit Form MMS-4415, as proposed in the December 
1999 proposal, but many express doubts that MMS will accept the 
location and quality differentials they derive and use in reporting 
royalties due. Industry commenters also do not believe that MMS can 
determine meaningful differentials for them when they are required to 
pay on an index value, but do not have actual information from their 
own contracts to determine these differentials. These commenters 
question how a company would challenge an MMS determination. Industry 
wants to be able to appeal determinations of differentials.
    MMS Response: If a lessee can document the differentials it uses 
from

[[Page 14056]]

its arm's-length exchange agreements or other reliable evidence, MMS 
will have little reason to dispute the lessee's use of those 
differentials. If MMS determines a location/quality differential, it 
will do so on the basis of the best information available to it. If the 
lessee disagrees with MMS's determination and the lessee and MMS are 
unable to resolve the disagreement, MMS would issue an order to the 
lessee to use MMS's differential. That order would be appealable.
(w) Elimination of Form MMS-4415 and Validity of Location/ Quality 
Differentials
    Summary of Comments: One State commenter supports keeping the Form 
MMS-4415 for now, with the provision that MMS can always eliminate the 
form in the future. That State asserts that it is better to collect the 
information now and realize later that the form is not needed rather 
than to be forced to work without it. One State believes that using 
location differentials to alternate disposal points (such as a 
refinery) is not appropriate, and that location differentials should be 
between the lease and the index pricing point.
    This commenter also asserts that exchange differentials will not 
accurately reflect the difference in value between the lease and the 
index pricing point. It proposes using gravity and sulfur banks in the 
pipeline tariffs for quality differentials. A public interest group 
recommends standardized location differentials.
    MMS Response: One of the most contentious issues arising from prior 
proposals in this rulemaking process has been the requirement for 
lessees to submit information about their exchange agreements on Form 
MMS-4415. These lessees correctly point out that the information is not 
for their benefit, but would be used only in a small number of cases 
where a lessee must pay on an index value, but does not have access to 
actual location/quality differential information. While it would be 
preferable to have comparable exchange differential information, MMS 
must weigh this benefit against the burden and cost that it would 
impose on industry and MMS. After considerable discussions with all 
interested parties, MMS has determined that the burdens and costs would 
outweigh the potential benefits. MMS anticipates that it will have to 
determine differentials for lessees in only a limited number of 
circumstances.
(x) Economic Analysis of Lease Markets
    Summary of Comments: On behalf of industry, one commenter asserts 
that MMS has ignored basic economic principles in arriving at the 
conclusion that lease markets are not competitive. MMS's conclusions, 
this commenter says, are based on contradictory statements, 
unsubstantiated claims, and misinterpretation of economic principles 
and significant facts about the domestic crude oil market. He states 
that the lease market contains significant and recurring volumes of 
crude oil sales moving in outright sales between unrelated, well-
informed buyers and sellers with access to information. Competition 
allows each party to protect its interests.
    MMS Response: MMS does not agree with this commenter and does not 
believe that his analysis of the lease market is complete. First, the 
commenter's analysis ignores the principle that the lessor is entitled 
to share in gains derived from the lessee's marketing activities. 
Second, relying on supposed comparable sales at the lease results in 
relying on prices paid to captive sellers in many instances. Those 
prices will tend to be below the true market value of the oil. Third, 
the commenter equates posted prices to ``price transparency.'' This 
assumption contradicts statements that companies with tendering 
programs have made during the rulemaking process, and cannot be 
defended under any concept of ``price transparency'' that we have been 
able to find. The fact that prices paid in arm's-length transactions 
frequently include a premium over the posted price refutes the 
commenter's assumption. The principles of competitive markets that this 
commenter outlines in fact occur at market centers with spot prices. 
Therefore, MMS believes it is appropriate to establish value for non-
arm's-length transactions by using spot prices, with adjustments for 
location and quality.
(y) Alleged Different Treatment of Integrated and Non-Integrated 
Producers
    Summary of Comments: Some industry commenters assert that 
integrated producers should not be treated differently than non-
integrated producers. Also, producers in the RMR have more options than 
producers in other regions. MMS should allow the same standards for all 
Federal leases, including tendering and comparable sales.
    MMS Response: MMS disagrees that integrated producers are treated 
differently than non-integrated producers under either the previous 
proposals or this final rule. How producers value production and pay 
royalties under this final rule depends in large measure on how they 
choose to market their production. If a producer sells its production 
outright at arm's length, it pays based on gross proceeds. If not, it 
pays royalties using either the index pricing methodology, an 
applicable benchmark (for production in the RMR), or on the basis of an 
arm's-length sale price following either inter-affiliate transfers or 
arm's-length exchanges. These principles apply to both integrated and 
non-integrated producers.
(z) Final Rule Implementation Date
    Summary of Comments: Industry commenters assert that MMS should 
allow for adequate time for industry to completely update its systems 
before the final rule becomes effective. (According to some industry 
commenters, it will require at least until the beginning of next year 
to update their systems.) A number of public interest groups stated 
that they expect a final rule in March 2000. A citizen and the State of 
New Mexico also favor immediate implementation of this rule.
    MMS Response: MMS understands that this rule will require some 
adjustments to many lessees' systems. It has extended its earlier 
proposed effective date to June 1, 2000, the first day of the first 
month more than 60 days after the publication date of this rule to 
allow lessees to make needed adjustments. MMS further has provided for 
a ``grace period'' in Sec. 206.121 that allows lessees to make 
adjustments to royalty payments for production in the first 3 months 
after the effective date of the rule without liability for late payment 
interest if the adjustment results from a system change necessary to 
comply with this rule. Lessees may get interest bills, but if they 
demonstrate that the adjustment generating the bill resulted from 
system changes necessitated by the rule, MMS will credit the bill. MMS 
believes that the ``grace period'' should allow adequate time for 
lessees to make necessary adjustments.
(aa) The Lessee's Duty to Market Production at No Cost to the Lessor
    Summary of Comments: Some industry commenters provided extensive 
comments on MMS's analysis in the December 1999 proposal of the 
lessee's duty to market production at no cost to the lessor and related 
issues (e.g., the commenters' view of valuing production ``at the 
lease'' and gain realized from ``downstream'' sales). (The analysis in 
the December 1999 proposal is reiterated with some additional 
explanation in Section III(i) above.) The industry commenters cite 
numerous

[[Page 14057]]

State court decisions, discuss IBLA precedents and various Federal 
court decisions at great length, and dispute the existence, scope and 
implications of the lessee's implied covenant to market the production 
for the mutual benefit of the lessee and the lessor. The State 
commenters support the MMS's position on the lessee's duty to market as 
reflected in the December 1999 proposal.
    MMS Response: The lessee's duty to market at no cost to the lessor 
is the subject of pending litigation. Industry has challenged a 
provision in the Department's December 16, 1997, gas transportation 
allowance rule that is virtually identical to the provision in the 
several proposals in this rulemaking and in this final rule (62 FR 
65753). See, American Petroleum Institute v. Babbitt, Civil No. 98-631 
and Independent Petroleum Association of America v. Armstrong, Civil 
No. 98-531 (D.D.C.) (consolidated). The ultimate resolution of this 
issue likely will lie with the courts. MMS believes the final rule is 
well within the agency's authority and reflects existing law governing 
Federal leases.
(ab) Affiliation and Control
    Summary of Comments: Some industry commenters believe that tests to 
determine control (and, consequently, affiliation in the event one 
person owns less than 50 percent of the voting securities of another) 
are too subjective.
    MMS Response: As explained elsewhere in this preamble, after the 
D.C. Circuit's decision in National Mining Association v. Department of 
the Interior, 177 F.3d 1 (D.C. Cir. 1999), MMS has no alternative but 
to conduct a fact-specific inquiry in cases where one person owns less 
than 50 percent of the voting securities of another. The situations 
vary widely. This rule identifies some of the key factors which MMS 
will examine in evaluating whether one person controls another. These 
factors are objective, not subjective, indicators. Their application 
depends on the facts of a particular case.
(ac) Production ``Tracing'' Issues
    Summary of Comments: Some industry commenters claim that tracing 
will involve multiple valuation determinations where none were needed 
before, and may make implementation of the rule impossible.
    MMS Response: The facts that oil produced from any particular lease 
or unit may be commingled with oil produced from other properties, and 
that the combined quantities may be disposed of through multiple 
transactions at more than one location, are not new. In many 
circumstances, the MMS valuation rules that hitherto have been in force 
require allocation of production from multiple sources and multiple 
dispositions if lessees are to pay royalty correctly. In fact, this 
rule provides the option to use index-based valuation, in which no 
``tracing'' would be required, in certain circumstances.
(ad) Tracing in Relation to Exchange Agreements
    Summary of Comments: Some States are concerned about the issue of 
tracing production after multiple exchanges. They assert that value can 
be masked in this process due to commingling and other factors. They 
favor limiting the number of exchanges or using a weighted average 
price if only one exchange exists. One public interest group favors 
limiting the number of exchanges to two.
    MMS Response: In cases where lessees have multiple exchanges 
involving production from a Federal lease, they will have to be able to 
account for adjustments due to location/quality differentials or 
transportation costs. These adjustments will be subject to audit. 
Lessees who dispose of production through arm's-length exchanges 
followed by an arm's-length sale have the option of valuing the 
production under either gross proceeds or index (Sec. 206.102(a) or 
Sec. 206.103, respectively). (Lessees who dispose of production through 
non-arm's-length exchanges or who refine their production must use the 
index value under Sec. 206.103.) If the lessee uses the index value 
under Sec. 206.103, the considerations the commenters raise are 
irrelevant. If the lessee values the production according to the arm's-
length gross proceeds following one or more arm's-length exchanges, it 
must be able to support its adjustments.
(ae) Treatment of and Effect on Affiliated Pipelines
    Summary of Comments: One pipeline commenter who is affiliated with 
producers said that the December 1999 proposal improperly affects 
affiliates negatively in several respects. This commenter said that MMS 
is trying to control the affiliate's pricing, transportation, and 
contracting behavior even though it is not a party to the lease. It 
also said that requiring production of an affiliate's pricing 
information could expose the affiliated pipeline to ``unreasonable 
allegations of antitrust violations.'' This commenter also says that 
the rule discriminates against affiliated transportation arrangements. 
The commenter further asserts that the rule imposes ``enormous'' 
administrative costs on affiliates and designees, which, it says, MMS 
``grossly underestimated.'' The commenter says that the rule would 
require multiple valuation methodologies, which in turn require new 
accounting systems and additional manpower. Finally, this commenter 
asserts that MMS lacks the statutory authority to require affiliates to 
make their records available.
    MMS Response: MMS disagrees with this commenter's 
characterizations. This rule does not control an affiliate's behavior. 
The fact that transactions with an affiliate may affect how production 
is valued for royalty purposes does not imply that the rule somehow 
``controls'' the affiliate's behavior.
    MMS does not believe that requiring production of an affiliate's 
information would create any exposure under the antitrust laws. In the 
commenter's own words, it fears that ``[p]laintiffs lawyers might try 
to concoct'' a Sherman Act theory. The commenter apparently does not 
believe that any such concocted theory would have any merit, and 
neither do we.
    As explained elsewhere in this preamble, the rule does not 
discriminate against affiliated transportation arrangements. In both 
arm's-length and non-arm's-length arrangements, the lessee may deduct 
its actual costs of transportation.
    We do not believe that the commenter has justified its assertion of 
``enormous'' administrative costs resulting from this rule. Although 
the rule does require changes in valuation methodology in some 
respects, no one has demonstrated that it requires lessees to construct 
completely new systems. Indeed, although companies have asserted 
repeatedly that the rule will result in large costs, none has attempted 
to quantify such costs.
    MMS believes that the commenter's assertion that the new rule 
requires ``multiple valuation methodologies'' is misplaced. We doubt 
that any lessee with more than a few leases valued all of its 
production for all of its leases in the same way under the previous 
rules. Under the prior rules, some dispositions resulted in using 
arm's-length gross proceeds as royalty value, while others resulted in 
using the ``benchmarks.'' MMS does not believe this rule is more 
difficult to apply than the earlier provisions; indeed, we expect that 
the opposite is true.
    Finally, the commenter's argument that MMS does not have statutory 
authority to require affiliates to produce their records is wrong. The 
commenter relies on the provisions of FOGRMA Section 103(a), 30 U.S.C. 
1713(a), for the proposition that MMS may require

[[Page 14058]]

production of records only through the first non-arm's-length transfer. 
This position was expressly rejected in Shell Oil Co. v. Babbitt, 125 
F.3d 172 (3d Cir. 1997). Contrary to the commenter's assertion, the 
affiliate is a person ``directly involved in . . . purchasing, or 
selling oil or gas subject to [FOGRMA] through the point of first sale 
or the point of royalty computation, whichever is later . . .''
(af) Pipeline Residual Return on Investment
    Summary of Comments: Many industry comments favored the proposed 
changes regarding a continued return on investment after a pipeline has 
been fully depreciated. Companies favored continuing to apply a rate of 
return against a minimum base value even after the pipeline has been 
fully depreciated. A few industry commenters were concerned as to how 
the calculation would be performed if original cost records no longer 
exist. States expressed concern that allowing a rate of return on some 
base value after the pipeline is fully depreciated amounts to an 
unnecessary gift to industry. One citizen also commented that the 
current regulations should remain, with no additional return on 
investment allowed beyond the normal life of a pipeline.
    MMS Response: MMS believes that, to cover factors such as the 
ongoing risk of operating a pipeline, it is reasonable to permit a 
residual return on investment component within the allowance 
calculation even after the pipeline has been almost completely 
depreciated. To account for such factors, this final rule, at 
Sec. 206.111(j), permits the allowance calculation to include an annual 
return on investment component of ten percent of the total capital 
investment in the pipeline, even after the pipeline has been 
depreciated to a level at or below 10 percent of the total capital 
investment.
    Under the final rule, we also added a provision at paragraph (j)(2) 
clarifying that you may apply this paragraph to a transportation system 
that before the effective date of the final rule is depreciated to a 
level at or below a value equal to ten percent of your total capital 
investment.
(ag) Definitions
    Summary of Comments: MMS received many comments that suggested 
various clarifications and modifications to definitions and terms used 
throughout the rule. Some groups offered specific suggestions. Others 
simply asked for additional clarification of some terms. Many comments 
focused on the definition of ``area'' and asserted that further 
clarification is warranted. One commenter noted that the rule as 
proposed would value some crude from the San Juan Basin one way if it 
were produced from surface wells in New Mexico or Arizona and another 
way if produced from surface wells in Utah or Colorado. The commenter 
recommended that the Four Corners area be treated consistently for 
valuation purposes because all production from the area generally is 
sold into the same market.
    MMS Response: Many of these terms used and defined in this rule 
were used in the previous rule, and further changes are not necessary. 
MMS agrees that the terms ``exchange for physicals'' and ``time 
trades'' can be removed from the definition of exchange agreement, and 
removed them in this final rule.
    MMS believes the defined term ``area'' requires no additional 
modification. This definition is similar to the definition in the 1988 
regulations. Moreover, this rule relies less on ``area'' than the 1988 
regulations did.
    However, we agree with the commenter who said production from the 
Four Corners area should be valued consistently. As a result we have 
modified the Rocky Mountain Region definition to mean the States of 
Colorado, Montana, North Dakota, South Dakota, Utah, and Wyoming, 
except for those portions of the San Juan Basin and, more generally, 
the ``Four Corners'' area that lie within Colorado and Utah.
(ah) Alleged Illegal Information Transfers for Transportation Allowance 
Calculations
    Summary of Comments: Some producers and industry groups commented 
that in order for them to calculate ``actual costs'' under the proposed 
rule, they need pipeline data from their affiliate. These commenters 
assert that the Interstate Commerce Act (ICA) prohibits the disclosure 
of this information. Even if this data was available and could be 
legally disclosed, they say MMS ignores the burden it now places on 
companies to compute this ``actual cost''.
    MMS Response: MMS believes that disclosure of pipeline cost 
information between affiliates is legal, the information is readily 
available, and affiliates have the right to exchange information and 
often do.
    The estimate of the cost burden related to calculation of ``actual 
transportation costs'' is embedded in the cost estimate for completing 
the Form MMS-2014, on which the allowance is reported, and is discussed 
in the ``Procedural Matters'' section of this preamble.
(ai) Cushing Spot Prices as a Benchmark in the Rocky Mountain Region
    Summary of Comments: A State commented, and some industry groups 
agreed, that using the Cushing, Oklahoma WTI spot price is not an 
appropriate measure of value for Wyoming crude oil. There may be only a 
few trades from Wyoming to Oklahoma, which means an accurate 
differential may be impossible to obtain.
    MMS Response: Valuation of oil produced in the RMR and not sold at 
arm's length is determined under a series of benchmarks. If the first 
benchmark does not apply, the lessee may select either the second or 
the third. The third is the WTI spot price at Cushing, Oklahoma. The 
lack of a dependable published spot price within the RMR prompted MMS 
to refer to the Cushing price. If the first two benchmarks cannot be 
applied, and the lessee believes the use of WTI in the third benchmark 
is not properly adjustable back to its property in Wyoming, the MMS 
Director may establish an alternate value under the fourth benchmark.

X. Summary and Discussion of Adopted Rules

    This final 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, the 
March 1999 notice, and the December 1999 proposal. As in the February 
1998 proposal, we also added and renumbered sections and further 
reorganized the rule for readability.
    This summary of adopted rules builds on the above summary of, and 
MMS's responses to, comments received on the January 1997, July 1997, 
September 1997, February 1998, July 1998, March 1999, and December 1999 
proposals and notices. Because this final 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 
the final rule.
    Note that the renumbering and reorganization for the final rule 
resulted in the following modifications to the existing rule at 30 CFR 
Subpart C-Federal Oil:

[[Page 14059]]



----------------------------------------------------------------------------------------------------------------
                           Section                                                Modification
----------------------------------------------------------------------------------------------------------------
Secs.  206.100 and 206.101...................................  Revised.
Secs.  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.
Secs.  206.105...............................................  Revised and redesignated as Secs.  206.110,
                                                                206.111, 206.114, 206.115, 206.116, 206.117, and
                                                                206.118.
Secs.  206.106...............................................  Revised and redesignated as Secs.  206.120.
                                                               New Secs.  206.112, 206.113, and 206.121 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 adopted rule, 
it is appropriate to reiterate the conceptual framework of the final 
rule. 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 final rule, 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, the final rule 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 will be based on appropriate index prices or 
other methods, as explained below.
    These principles 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 apply if an 
arm's-length exchange occurs before an arm's-length sale. (However, MMS 
believes that if there are multiple exchanges prior to 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 has 
provided the option to determine value based either on the arm's-length 
gross proceeds or on an index or benchmark basis. The same option is 
provided for valuing production that is first sold or transferred to an 
affiliate and then resold at arm's length.)
    Lessees and producers may structure their business arrangements 
however they wish, but MMS generally will look to the ultimate arm's-
length disposition in the open market as the best measure of value. 
This means that MMS will not be ``second-guessing'' industry business 
decisions. Where a true arm's-length sale occurs that has not been 
preceded by non-arm's-length exchanges, the gross proceeds from that 
sale will represent royalty value, absent misconduct on the part of the 
lessee or breach of express or implied lease covenants, unless the 
lessee opts to apply index or benchmark values in appropriate 
situations.
    Nor does the express language regarding the lessee's obligation to 
market production for the mutual benefit of the lessee and the lessor 
give MMS a license to ``second-guess'' marketing decisions. As 
discussed above, that obligation has always been an implied covenant of 
the lease.
    Similarly, if oil is refined without being sold at arm's length, 
MMS believes that the valuation methods prescribed in this final rule 
are the best measures of value regardless of internal, inter-affiliate, 
or other non-arm's-length transfers.
    Another important feature of the final rule is separate valuation 
procedures for California and Alaska, the RMR, and the rest of the 
country. In California and Alaska, if oil is not sold under an arm's-
length contract, value would be based on ANS spot prices, adjusted for 
location and quality. MMS chose this indicator because it believes that 
ANS is the best measure of market value in that area when oil is not 
sold at arm's length.
    In the RMR, if oil is not sold under an arm's-length contract, 
market value is more difficult to measure because of the isolated 
nature of the RMR from the major oil market centers. Therefore, MMS 
will accept values established by a company-administered tendering 
program as the first benchmark.
    If the company does not have an approved tendering program, it may 
choose either the second or third benchmark. The second benchmark is a 
volume-weighted average of the gravity-normalized prices at which the 
lessee and its affiliates purchase or sell production from both Federal 
and non-Federal leases in the field or area at arm's length, if those 
arm's-length sales and purchases exceed 50 percent of the lessee's and 
its affiliates' production.
    The third benchmark is the spot price for WTI crude at Cushing, 
Oklahoma, with location and quality adjustments. MMS chose the Cushing 
spot price because no acceptable published spot price exists in the 
RMR. If none of the first three benchmarks results in a reasonable 
value, the MMS Director may establish an alternative valuation method.
    For other areas of the country, value would be based on the nearest 
spot price for oil of similar quality to your production, adjusted for 
quality and location. MMS believes that because the spot market is so 
active in areas other than the RMR, it is the best indicator of value 
in those other areas.

Section 206.100  What Is the Purpose of This Subpart?

    As proposed in December 1999, this section includes the content of 
the existing section except for minor wording changes to improve 
clarity, additional language in new Sec. 206.100(b) clarifying the 
respective roles of lessees and designees, and additional wording in 
Sec. 206.100(d)(3) regarding written valuation agreements between the 
lessee and the MMS Director. (``Lessees'' and ``designees'' 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. Sec. 1702, as amended by Section 2 of the Federal Oil and Gas 
Royalty Simplification and Fairness Act, Pub. L. No. 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 refer to you and not to the lessee. In this event, 
you must 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'' refer to 
the lessee and not the designee. In that

[[Page 14060]]

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 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) realized on the sale to the purchaser.
    In some cases, a lessee sells its production directly to a 
designee. (In such cases, the designee frequently is the operator but 
it does not have to be.) Questions may arise regarding whether such an 
arrangement is actually a sale or is an arrangement for the designee to 
dispose of the production on behalf of the lessee. These questions were 
raised during the January 2000 public workshops.
    Several scenarios are possible, and each case will have to be 
considered on its facts. Nevertheless, there are some indicators MMS 
will examine in determining whether a designee is disposing of 
production on behalf of a lessee or is purchasing the production from 
the lessee. These indicators include but are not limited to the 
following:
     If a lessee sells to an unaffiliated designee where there 
is no joint operating agreement and the designee or its affiliate 
refines the oil rather than selling it, MMS ordinarily would regard 
this arrangement as an arm's-length sale and accept the price as 
royalty value.
     If a lessee sells to a co-lessee/designee under a joint 
operating agreement, MMS ordinarily will regard that arrangement as the 
designee disposing of production on the lessee's behalf and not as an 
actual sale to the designee.
     If the price paid to the lessee by the designee is 
dependent on the designee's receipts on resale of the production (e.g., 
a specified percentage of the co-lessee's receipts), MMS ordinarily 
will regard that arrangement as the designee disposing of the 
production on the lessee's behalf and not as a sale. (In this 
situation, even if the transaction were regarded as an arm's-length 
sale, the designee is most likely the lessee's marketing agent in any 
event. Thus, the difference in price between the designee's receipts 
and what it pays the lessee would reflect the lessee's marketing costs, 
which it may not deduct from royalty value.)
    We also note that the question of whether a lessee is selling to a 
designee (as opposed to the designee disposing of production on the 
lessee's behalf) is related to the larger question of whether a sale to 
a co-lessee (including one who is not a designee) is an arm's-length 
sale as opposed to an arrangement where the co-lessee is the lessee's 
marketing agent. MMS acknowledges that there are many cases in which a 
lessee sells to a co-lessee (whether a designee or not) at arm's 
length. But there are also many cases in which a co-lessee effectively 
acts as the marketing agent for the lessee. We will discuss this 
question further below in connection with arm's-length sales under 
Sec. 206.102(a).
    Revised Sec. 206.100(a) is the same as the corresponding paragraph 
in the existing rule, rewritten for clarity. New Sec. 206.100(b) 
clarifies the respective roles of lessees and designees.
    New Sec. 206.100(d) is essentially the same as existing 
Sec. 206.100(b). That provision says that if any Federal statute, 
settlement agreement between the United States and a lessee resulting 
from administrative or judicial litigation, or oil and gas lease 
subject to the requirements of this subpart is inconsistent with any 
regulation in this subpart, then the statute, lease provision, or 
settlement agreement governs to the extent of the inconsistency. 
However, we added a separate provision at new Sec. 206.100(d)(3). It 
says that if a written agreement between the lessee and the MMS 
Director establishes a production valuation method for any lease that 
MMS expects at least would approximate the value otherwise established 
under this subpart, the written agreement will govern to the extent of 
any inconsistency with the regulations. This provision is intended to 
provide flexibility to both MMS and the lessee in those few unusual 
circumstances where a separate written agreement is reached, while at 
the same time maintaining the integrity of the regulations. As noted, 
any such agreement also must at least approximate the royalty value 
that would apply under these regulations for the production.
    The content of new Sec. 206.100(e) is the same as in existing 
paragraph (c), but rewritten for clarity. It says MMS may audit and 
adjust all royalty payments.
    Section 206.100 also reflects the principle that this rule 
constitutes the Secretary's exercise of his authority reserved under 
the statutes and lease terms to establish the reasonable value of 
production for royalty purposes. MMS will not look to other possible 
measures of value that may be referenced in the lease terms (for 
example, the so-called ``major portion'' value) to supersede these 
rules, except in those few unusual circumstances where MMS and the 
lessee establish a written royalty valuation agreement under 
Sec. 206.100(d)(3).
    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 Sec. 206.50 that include the same language as existing paragraph 
(d), the existing language at paragraph 206.100(d) is not needed.

Section 206.101  What Definitions Apply to This Subpart?

    The definitions section in the final rule remains virtually the 
same as in the December 1999 proposal. The preamble to that proposal 
explains thoroughly each of the changes to definitions previously 
proposed (64 FR at 73825-73827). Several of these definitions also have 
been discussed at various points earlier in this preamble. The only 
changes in the final rule to the definitions proposed in December 1999 
are:
     Affiliate--We changed one detail of the definition 
proposed in December 1999. That definition said that if there is 
ownership or common ownership of between 10 and 50 percent of another

[[Page 14061]]

person, MMS will consider various factors in determining whether 
control exists. One of those factors involves forms of ownership, 
including percentage of ownership or common ownership, the relative 
percentage of such ownership compared to percentages of ownership by 
other persons, whether a person is the greatest single owner, and 
whether there is an opposing voting bloc of greater ownership. We 
changed the and preceding the final clause to or in the final rule. We 
did this to avoid the implication that all of the listed factors carry 
equal weight in all situations or that if one factor does not apply, 
then none of them does. MMS may consider any one of the factors in 
subparagraph (2) of the definition to establish control.
     Exchange agreement--We have removed the examples included 
in the December 1999 proposal of exchanges of produced oil for futures 
contracts (Exchanges for Physical, or EFP) and exchanges of produced 
oil for similar oil produced in different months (Time Trades) because 
these trades or exchanges involve different time periods and may not 
reflect reliable location/quality differentials applicable to royalty 
payment for a particular production month.
     Location differential--We added language clarifying that 
the amount paid or received as a location differential under an 
exchange agreement may be expressed in terms of either money or barrels 
of oil.
     Quality Differential--We added language clarifying that 
the amount paid or received as a quality differential under an exchange 
agreement may be expressed in terms of either money or barrels of oil.
     Trading Month--We added this definition to clarify the 
changes we made in the final rule regarding the timing and application 
of spot prices under Sec. 206.103. We also believe use of this term 
will help in understanding the general concepts of spot price 
formulation and application. Trading month means the span of time 
during which crude oil trading occurs and spot prices are determined, 
generally for deliveries of corresponding production in the following 
month. (We use the term ``generally'' only because for West Texas 
Intermediate at Cushing, Oklahoma, spot prices are published for 
deliveries both in the following month and the second-following month.) 
For Alaska North Slope (ANS) spot prices, the trading month includes 
the entire calendar month. For other domestic spot prices, the trading 
month includes the span of time from the 26th of the previous month 
through the 25th of the current month.

Section 206.102   How do I Calculate Royalty Value for Oil That I or My 
Affiliate Sell Under an Arm's-Length Contract?

    In the December 1999 proposal, we revised and reorganized 
Sec. 206.102 as written in the several previous proposed rules. We 
revised Sec. 206.102 to specifically address valuation of oil 
ultimately sold under arm's-length contracts. We have adopted 
Sec. 206.102 as proposed in December 1999 with only a few minor changes 
in wording for clarification.
    An arm's-length 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.
    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, and that 
person or its affiliate then sells the oil at arm's length, royalty 
value is the other person's (or its affiliate's) gross proceeds under 
the arm's-length contract.
    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 single working interest owner 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 at 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 arm's length. Because the result of both paragraphs 
would be the same, and to stem this confusion, the December 1999 
proposal eliminated previous paragraph (a)(3) and included its intent 
in revised paragraph (a)(2), which we adopt in the final rule. That 
paragraph now says 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 unless 
you exercise the option provided in paragraph (d)(2) of this section. 
As a result of this change, paragraph (a)(4) of the February 1998 
proposal now becomes Sec. 206.102(c).
    In all these circumstances, you must 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).
    Because a lessee may sell oil to a co-lessee, questions arise 
regarding whether a sale to an unaffiliated co-lessee (particularly a 
co-lessee who is an operator) is an arm's-length sale or is really a 
marketing arrangement (with the purchasing co-lessee acting as the 
lessee's marketing agent). As noted in the discussion of Sec. 206.100 
above, these questions are closely related to the question of whether a 
co-lessee who is also a designee is disposing of production on the 
lessee's behalf or whether it is buying the lessee's production, which 
was raised in the January 2000 public workshops. MMS acknowledges that 
there are cases in which a lessee sells to a co-lessee at arm's length 
and in which the arm's-length sales price is the royalty value. But 
there are also many cases in which a co-lessee effectively acts as the 
marketing agent for the lessee.
    Possible factual scenarios may vary widely, and each case must be 
evaluated on its facts. MMS may look to a number of factors. These 
include, but are not limited to, the following:
     If the purchasing co-lessee or its affiliate refines the 
oil rather than reselling it, MMS ordinarily will regard the sale as an 
arm's-length sale.
     If the sales price under the contract with the co-lessee 
is dependent on the co-lessee's resale receipts, MMS ordinarily will 
regard the co-lessee as the lessee's marketing agent.
     If the co-lessee disposes of production under a joint 
operating agreement, MMS ordinarily will regard

[[Page 14062]]

the co-lessee as the lessee's marketing agent.
    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 remained unchanged in the 
December 1999 proposal. The final rule reflects the February 1998 
proposal and the December 1999 proposal in this regard without change.
    Paragraph (b) clarifies 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 is 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.
    Paragraph (c) specifies two exceptions to the use of arm's-length 
gross proceeds. It also requires you to apply the exceptions to each of 
your contracts separately.
    Paragraphs (c)(1) and (c)(2) remain essentially unchanged from 
paragraphs (a)(2) and (a)(3) in the January 1997 proposal. Note, 
however, that 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. As explained in the 
December 1999 proposal, 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). There were no comments in response 
to the December 1999 proposal that added any new informative analysis 
on this question. Thus, the final rule does not contain any specific 
language regarding balancing agreements.
    Likewise, the final rule does not contain any specific language 
regarding 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 agreed with this point in the December 1999 proposal. In 
the final rule, oil subject to a noncompetitive crude oil call will 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 will be the 
lessee's total consideration or the value determined by the non-arm's-
length methods in Sec. 206.103.
    In the July 1997 proposal, MMS modified paragraph (a)(4) of the 
January 1997 proposal regarding exchange agreements and crude oil 
calls. It also proposed a new paragraph (a)(6) regarding exchange 
agreements. See the preamble to the July 1997 proposal at 62 FR 36031 
for a complete explanation of the changes proposed. In the February 
1998 proposal, we further modified the exchange agreement language at 
paragraphs (a)(4)(i) and (a)(6) of the July 1997 proposal and combined 
it in paragraph (c)(3). That paragraph required use of Sec. 206.103 to 
value oil you dispose of under an exchange agreement. But if you 
entered into one or more arm's-length exchange agreements, and after 
these exchanges you or your affiliate disposed of the oil in an arm's-
length sale, you would value the oil under paragraph (a) on the basis 
of the gross proceeds received under the arm's-length contract for the 
sale of the oil received in exchange. You would adjust the value 
determined under paragraph (a) for location or quality differentials or 
any other adjustments you received or paid under the arm's-length 
exchange agreement(s). However, if MMS found that any such 
differentials or adjustments weren't reasonable, it could require you 
to value the oil under Sec. 206.103.
    This concept was similar to paragraph (a)(6)(i) of the July 1997 
proposal, but with three differences. First, the July 1997 language 
referred to exchange agreements with a person not affiliated with you. 
The February 1998 proposal clarified that this covered arm's-length 
exchange agreements. This meant that not only must you be unaffiliated 
with your exchange partner, but there must be opposing economic 
interests regarding the exchange agreement. MMS believed this would 
limit instances where inappropriate or unreasonable location, quality, 
or other adjustments would be applied. MMS proposed to limit this 
provision to arm's-length exchanges because it believed transportation, 
location, and quality differentials stated in non-arm's-length exchange 
agreements are not reliable.
    Second, MMS clarified that the same valuation procedure would apply 
if there is more than one arm's-length exchange. For example, if you 
entered into two sequential arm's-length exchanges for your Federal oil 
production and then you or an affiliate sold the reacquired oil at 
arm's length, you would value your production under paragraph (a) under 
the February 1998 proposal. MMS believed that as long as the integrity 
of the differentials and adjustments was maintained, there was no 
reason not to look to the ultimate arm's-length sale proceeds.
    Third, under paragraph (a)(6)(i) of the July 1997 proposal, if you 
disposed of your oil under an exchange agreement with a non-affiliate 
and after the exchange you sold the acquired oil at arm's length, you 
could have elected to value your oil either at your gross proceeds or 
under index pricing. MMS eliminated this option in the February 1998 
proposal, believing that the actual arm's-length disposition should 
govern valuation. That is, the provisions of Secs. 206.102 or 206.103 
would have been applied according to your actual circumstances. This 
change also led to the deletion of the previously-proposed paragraph 
(a)(6)(iii), which related to

[[Page 14063]]

the election we eliminated in the February 1998 proposal.
    As a result of the changes discussed previously, MMS also 
eliminated paragraph (a)(6)(ii) of the July 1997 proposal. This 
paragraph would have required you to use index pricing if you either 
transferred your oil to an affiliate before the exchange occurred, 
transferred the oil you received in the exchange to an affiliate, or 
entered into a second exchange for the oil you received back under the 
first exchange. MMS believes that if you transfer your production to an 
affiliate and the affiliate then enters into an arm's-length exchange 
and sells the oil received in the exchange at arm's length, the arm's-
length proceeds should be the measure of value. Likewise, if you enter 
an arm's-length exchange but then transfer the oil received to an 
affiliate who resells the oil at arm's length, the arm's-length 
proceeds should be the measure of value. For any exchanges where the 
oil received in return is not resold but instead is refined, index 
prices would apply as discussed under Sec. 206.103.
    However, we received numerous comments about the problems of 
tracing value back to the lease where an arm's-length sale follows 
multiple arm's-length exchanges. Commenters insisted it would be a 
monumental task for lessees to track, and for MMS to verify, the 
multiple transactions involved. Further, the problems involved in such 
``tracing'' are aggravated when the necessary records are in the 
possession of independent third parties who are not affiliates of the 
lessee.
    As a result, in our July 1998 proposal we modified paragraph 
206.102(c)(3) of the February 1998 proposal to require valuation under 
paragraph 206.102(a) only if you enter into a single arm's-length 
exchange agreement and following that exchange you dispose of the oil 
in a transaction to which paragraph (a) applies. If you entered into 
multiple exchanges to dispose of your production, you would have used 
Sec. 206.103 to value that production. However, some commenters on the 
July 1998 proposal believed they also should be able to use their 
arm's-length gross proceeds following multiple arm's-length exchanges.
    Therefore, the December 1999 proposal, at paragraph 206.102(d)(1), 
provided 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. 
To prevent potential abuses of this option, paragraph 206.102(d)(1)(ii) 
provides that you must apply the option you select for all of your 
production from the same unit, communitization agreement, or lease (if 
the lease is not part of a unit or communitization agreement) sold at 
arm's length following arm's-length exchange agreements. You may not 
change this election more often than once every 2 years. We believe 
this process achieves the best balance of valuing production based on 
arm's-length gross proceeds and minimizing the administrative problems 
for all involved, and have adopted it in the final rule.
    We reiterate that you must use Sec. 206.103 to value oil disposed 
of under an arm's-length contract following one or more non-arm's-
length exchanges. MMS does not believe it is appropriate to use the 
terms of non-arm's-length exchange agreements to adjust the arm's-
length gross proceeds because the differentials in such agreements may 
not accurately reflect market rates.
    Paragraph (d)(2) of this final rule was proposed in December 1999, 
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 the final rule, 
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, paragraph (d)(2)(ii) states that you must apply the option you 
select for all of your production from the same unit, communitization 
agreement, or lease (if the lease is not part of a unit or 
communitization agreement) disposed of through affiliate resales at 
arm's length. You may 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.
    Paragraph (e) is the same as the December 1999 proposal, and is 
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. We have 
eliminated 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. Also, since this final rule generally requires arm's-length 
gross proceeds as royalty value regardless of whether the lessee, an 
affiliate, or another person to whom the lessee has sold or transferred 
production under a non-arm's-length contract is the person who 
ultimately sells at arm's length, all of these persons come within the 
term ``seller.''

Section 206.103  How Do I Value Oil That I Cannot Value Under 
Sec. 206.102?

    In the February 1998 proposal, this section replaced paragraph 
206.102(c) of the January 1997 proposal. The December 1999 proposal 
included a few changes to this section. The final rule makes a few 
further changes in this section as explained below.
    This section deals specifically with valuation of oil you cannot 
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 also 
applies where you have elected one of the options available at 
Sec. 206.102(d)(1) or (2).
    The February 1998 proposal made a change (continued in the December 
1999 proposal) from the January 1997 proposal for value based on index 
prices. In MMS's initial proposal, where either NYMEX or spot prices 
were applied in valuation, the prices for the month following the lease 
production month were used. This was meant to reflect the fact that 
spot prices and NYMEX futures prices for the following month are 
determined during the month of production. MMS believed this best 
reflected market value at the time of production. However, various 
commenters asserted that, for application of spot or futures prices, 
the lease production month should coincide with the spot or futures 
delivery month. They said this would effectively match production to 
index prices for deliveries in the same month. In the February 1998 and 
December 1999 proposals, we accordingly changed the timing of 
application of index prices so that the lease production month and the 
spot delivery month would coincide.
    However, as explained above, further examination has led us to 
believe that in some cases the use of spot prices determined before the 
production month could affect lessees' production decisions and, 
ultimately, royalties paid. See Section VI(e) above. For the reasons 
stated there, the final rule applies the spot price effectively 
determined during the production month so that price determination is 
concurrent with production.
    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

[[Page 14064]]

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 final rule 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 
lessors while assuring receipt of fair royalty values.
    Another change from the January 1997 proposal is an additional 
geographic breakdown for valuation purposes. The original proposed rule 
included separate valuation procedures for California and Alaska 
separately from the rest of the country. But based on the various 
written comments MMS received in response to its January 1997, July 
1997, September 1997, February 1998, July 1998, March 1999, and 
December 1999 proposals and notices, and comments made at the various 
valuation workshops and hearings, it became apparent that oil marketing 
and valuation in the RMR is significantly different from other areas. 
Also, the only published spot price in the RMR is at Guernsey, Wyoming. 
Most commenters consistently maintained that the spot price there is 
based on thinly-traded volumes. The combination of geographical 
remoteness from midcontinent markets, unique marketing situations, and 
the lack of a meaningful published spot price led MMS to add the RMR as 
a third royalty valuation region.
    Paragraph 206.103(a) applies to production from leases in 
California or Alaska. It replaces paragraph 206.102(c)(2)(ii) of the 
January 1997 proposal and includes a change from the December 1999 
proposal. Under the final rule, value is the average of the daily mean 
ANS spot prices, published in any MMS-approved publication, that apply 
to the month following the production month (instead of those published 
during the calendar month preceding the production month). You must 
adjust the value for applicable location and quality differentials, and 
you may adjust the value for transportation costs, as described at 
Sec. 206.112. The only change in this final rule is a more detailed 
explanation of how to calculate the spot prices.
    To calculate the daily mean spot prices, average the published 
daily high and low prices published during the production month, only 
using the days and corresponding prices for which spot prices are 
published. Do not include weekends, holidays, or any other days when 
spot prices are not published. For example, assume the production month 
has 31 days, including 8 weekend days and a holiday, and the 
publication publishes spot prices for all other days. You would average 
together the published high and low spot prices for each of the 22 
remaining days.
    An example of the index pricing method utilizing ANS spot prices 
for California production follows. Assume that the production month is 
December 1999 and that we take data from an MMS-approved publication. 
To reflect the market's assessment of value during the production 
month, use the spot prices published during December 1999 (for the 
January 2000 spot sales delivery month). The daily mean spot price 
assessments during December 1999 are averaged to arrive at the ANS 
price basis, in this case $24.5469 per barrel. This price would be 
adjusted for location/quality differentials and transportation (as 
discussed elsewhere in this preamble) in determining the proper value 
of your oil. The following table illustrates the calculation in this 
example:

                                  Alaska North Slope Spot Prices--December 1999
                          [Prices for January 2000 Delivery, December 1999 Production]
----------------------------------------------------------------------------------------------------------------
                           Date                                Low ($/bbl)       High($/bbl)         Average
----------------------------------------------------------------------------------------------------------------
12/01/99..................................................           23.3300           23.4000           23.3650
12/02/99..................................................           24.0500           24.1200           24.0850
12/03/99..................................................           24.0900           24.1500           24.1200
12/06/99..................................................           24.9500           25.0600           25.0050
12/07/99..................................................           24.6000           24.6800           24.6400
12/08/99..................................................           24.9000           24.9500           24.9250
12/09/99..................................................           24.6000           24.6500           24.6250
12/10/99..................................................           23.9500           24.0100           23.9800
12/13/99..................................................           23.8500           23.9100           23.8800
12/14/99..................................................           24.3300           24.4000           24.3650
12/15/99..................................................           24.8300           24.9100           24.8700
12/16/99..................................................           25.3500           25.4100           25.3800
12/17/99..................................................           25.2500           25.2800           25.2650
12/20/99..................................................           24.9000           25.0300           24.9650
12/21/99..................................................           24.7100           24.7500           24.7300
12/22/99..................................................           23.9400           24.0000           23.9700
12/23/99..................................................           24.4100           24.4400           24.4250
12/27/99..................................................           24.7500           24.8400           24.7950
12/28/99..................................................           25.2400           25.3100           25.2750
12/29/99..................................................           24.6000           24.6500           24.6250
12/30/99..................................................           24.1700           24.2200           24.1950
                                                           -----------------------------------------------------
    Average...............................................           24.5143           24.5795           24.5469
----------------------------------------------------------------------------------------------------------------

    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,

[[Page 14065]]

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 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.
    MMS has received comments to the effect that a court decision in 
favor of Exxon in California demonstrates that adjusted ANS prices do 
not reflect reasonable values for California crude oil. MMS disagrees 
because the facts in the Exxon case are different and the leases 
involved are not Federal leases.
    The State of California and the City of Long Beach first sued Exxon 
in the mid-1970s alleging that Exxon (along with other major producers) 
had conspired to keep posted prices low and that the State and City had 
been damaged because their oil revenues depended on posted prices. The 
contracts with the City required oil value at the higher of posted 
prices or prices paid at Wilmington or three nearby fields. The City 
and State contended that true value was higher and should be tied to 
ANS prices. The State and City ultimately took the case against Exxon 
to a jury trial before the Los Angeles County Superior Court on a 
breach-of-contract claim. On August 30, 1999, the jury found that Exxon 
did not act in bad faith or manipulate prices for oil produced from the 
Wilmington field from 1981-1989, and had conformed to its contract 
requirements.
    A jury verdict does not constitute a legal ruling on Federal leases 
or on Federal royalty issues. The contract terms were very specifically 
tied to posted prices or prices received in the immediate area. Federal 
oil leases require royalty payments based on different principles than 
those used by the jury. Rather than a contract price agreed on in 
advance, Federal oil royalties are tied to regulations that require 
different valuation procedures depending on how the oil is sold.
    The lands at issue in the Exxon case were State-owned and not 
leased. The companies participating in their development bought most of 
the oil produced. This situation is much different from a Federal 
lessee paying a royalty on the value of production. For all of these 
reasons, the Exxon State court decision has no applicability here.
    Paragraph 206.103(b) applies to production from leases in the Rocky 
Mountain Region, a defined term. As discussed above, production in the 
RMR 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 
RMR.
    As noted above, all of the previous proposals defined the Rocky 
Mountain Region as the States of Wyoming, Montana, North Dakota, South 
Dakota, Colorado, and Utah. However, portions of southern Colorado and 
southern Utah encompass parts of the San Juan Basin and, more 
generally, the ``Four Corners'' area. (The ``Four Corners'' is the 
convergence of the boundaries of New Mexico, Arizona, Utah, and 
Colorado.) New Mexico and Arizona are not part of the RMR. Parts of the 
San Juan Basin and the Four Corners area are within the boundaries of 
those States. Oil produced from the San Juan Basin and the Four Corners 
area typically is sold or exchanged to midcontinent markets (such as 
Midland, Texas), where dependable spot prices are published.
    One commenter on the December 1999 proposal noted that the rule as 
proposed would value some crude from the San Juan Basin one way if it 
were produced from surface wells in New Mexico or Arizona and another 
way if produced from surface wells in Utah or Colorado. The commenter 
recommended that the Four Corners area be treated consistently for 
valuation purposes because all production from the area generally is 
sold into the same market.
    There was no logical reason to treat those portions of the San Juan 
Basin or the Four Corners area that lie within Colorado or Utah any 
differently than those parts that lie within New Mexico or Arizona. 
Accordingly, we have excluded them from the definition of Rocky 
Mountain Region. Consequently, you must value oil produced from leases 
in these areas under the standards applicable to the remainder of the 
country.
    For the reasons explained above, we derived a series of valuation 
benchmarks for the RMR. The final rule makes one change from the 
December 1999 proposal, as discussed below.
    The first benchmark applies if you have an MMS-approved tendering 
program (a defined term). The value of production from leases in the 
area the tendering program covers is the highest price bid for tendered 
volumes. Under your tendering program you must offer and sell at least 
30 percent of your production from both Federal and non-Federal leases 
in that area. You also must receive at least three bids for the 
tendered volumes from bidders who do not have their own tendering 
programs that cover some or all of the same area.
    MMS added the several qualifications stated above to ensure receipt 
of market value under tendering programs. First, royalty value must be 
the highest winning bid price 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 
winning bid received.
    Second, you must 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 RMR the combined Federal royalty rate and State composite 
effective tax rate on Federal oil production typically ranges from 
about 17 percent to about 27 percent. These percentages do not include 
State royalty rates. In the December 1999 proposal, we therefore chose 
30 percent, or just above the high end of the royalty/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

[[Page 14066]]

production volumes in the 30 percent determination to ensure that the 
program isn't aimed at limiting Federal royalty value. Nothing in the 
comments in response to the December 1999 proposal persuasively 
rebutted this analysis. We have adopted the December 1999 proposal in 
the final rule.
    Third, to ensure receipt of competitive bids, your tendering 
program must result in at least three bids from bidders who do not have 
their own tendering programs covering some or all of the same area. MMS 
believes that requiring a minimum number of bidders is needed to ensure 
receipt of market value. In our February 1998 proposal we stipulated a 
minimum of three bids. However, 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. The December 1999 
proposal reviewed this criterion, and maintained the view that a 
minimum number of bidders is essential to ensure receipt of market 
value. We believe that at least three bidders are needed and have 
retained this provision in the final rule. (A lessee may receive more 
bids, including from bidders who have tendering programs of their own, 
but at least three bids must be from bidders who do not have their own 
tendering programs.) 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 three bids must come from 
bidders who do not also have their own tendering programs in the area.
    Under the final rule, if the first benchmark (an approved tendering 
program) does not apply, you may choose between the second and third 
benchmarks. In the February 1998 and December 1999 proposals, the 
benchmarks were strictly hierarchical. We have changed to permitting a 
choice between the second and third benchmarks in response to comments 
received in the January 2000 public workshops. However, consistent with 
other options provided in the final rule, you must make the same 
election for all of your production from the same unit, communitization 
agreement, or lease (if the lease is not part of a unit or 
communitization agreement) that you cannot value under Sec. 206.102 or 
that you elect under Sec. 206.102(d) to value under this section. After 
you select either paragraph (2) or (3), you may not change to the other 
method more often than every 2 years, unless the method you have been 
using is no longer applicable and you must apply the other paragraph. 
If you change methods, you must begin a new 2-year period.
    Under the second benchmark, value is the volume-weighted average 
gross proceeds accruing to the seller under your and your affiliates' 
arm's-length contracts for the purchase or sale of production from the 
field or area during the production month. The benchmark itself is not 
changed from the December 1999 proposal. The total volume purchased or 
sold under those contracts must exceed 50 percent of your and your 
affiliates' production from both Federal and non-Federal leases in the 
same field or area during that month.
    MMS developed this method as one alternative if you do not have an 
approved tendering program, and as an effort to establish value based 
on actual transactions by the lessee and its 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. As we explained in 
the December 1999 proposal, that is because the 50 percent floor 
applies 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. It 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 Company B are 6,000 
barrels, or 60 percent of the lessee's and its affiliates' 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 represents royalty value for the 9,000 barrels of Company A's 
Federal lease production in the field that cannot be valued under 
Sec. 206.102.
    This final rule requires 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. As explained in the December 1999 proposal, 
we believe that production in the same field or area generally will be 
similar in quality. However, in the final rule, based on comments 
received in the January 2000 workshops, we have included a requirement 
that before calculating the volume-weighted average, you must normalize 
the quality of the oil in your or your affiliate's arms-length 
purchases or sales to the same gravity as that of the oil produced from 
the lease. Further, given that these sales and purchases must 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.
    As explained in the December 1999 proposal, we do not 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 will 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 rule.

[[Page 14067]]

    The third benchmark value is the average of the daily mean spot 
prices published in any MMS-approved publication for WTI crude at 
Cushing, Oklahoma, applicable to deliveries during the month following 
the production month. You must calculate the daily mean spot price by 
averaging the daily high and low prices for the month in the selected 
publication. Use only the days and corresponding spot prices for which 
such prices are published. You must adjust the value for applicable 
location and quality differentials, and you may adjust it for 
transportation costs, under Sec. 206.112 of this subpart. An 
illustration of how the spot price value is calculated is given below 
in the discussion of spot price values for areas other than California 
and Alaska and the RMR.
    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 the final rule. 
This was due to an industry comment that since Cushing spot and NYMEX 
futures prices track closely over time and that we use spot prices in 
the other two valuation regions, using the spot price in the RMR would 
lend consistency with no downside effects. As noted earlier, in the 
final rule we correlated the spot price determination period with the 
trade month, rather than the delivery month. As provided in the 
previous proposals, the final rule provides that if you demonstrate to 
MMS's satisfaction that paragraphs (b)(1) through (b)(3) 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 is intended to be used only 
in very limited and highly unusual circumstances. We believe there 
should be very few such alternative valuation methods.
    We received several comments that this option should be offered 
nationwide. However, as we explained in the December 1999 proposal, 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 RMR 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) applies to production from leases not located 
in California, Alaska, or the RMR. As proposed in December 1999, MMS 
has modified paragraph 206.102(c)(2)(i) of the January 1997 proposal 
that applied to locations other than California and Alaska. That 
paragraph would have required you to value your oil at the average 
daily NYMEX futures settle prices. In this final rule, value is the 
average of the daily mean spot prices:
    (1) For the market center nearest your lease where spot prices for 
crude oil similar in quality to that of your production are published 
in an MMS-approved publication. (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 may use this 
alternate market center to value your production.);
    (2) For that similar quality crude oil. (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 must use the spot price 
for the oil that is most similar to your production.); and
    (3) That are applicable to the month following the production 
month.
    An example of the index pricing method utilizing Empire, Louisiana 
spot prices for Heavy Louisiana Sweet production follows. Assume that 
the production month is December 1999 and that we take data from an 
MMS-approved publication. To reflect the market's assessment of value 
during the production month, use the spot price published for each 
business day beginning with November 26, 1999, and ending with December 
25, 1999 (for the January 2000 spot sales delivery month). The daily 
mean spot price assessments during the period November 26, 1999--
December 25, 1999 are averaged to arrive at the Empire spot price 
basis, in this case $26.3089 per barrel. This price would be adjusted 
for location/quality differentials and transportation (as discussed 
elsewhere in this preamble) in determining the proper value of your oil 
for December 1999 production. The following table illustrates the 
calculation in this example:

                      Heavy Louisiana Sweet (Empire, Louisiana) Spot Prices.--December 1999
                          [Prices for January 2000 Delivery, December 1999 Production]
----------------------------------------------------------------------------------------------------------------
                           Date                                Low ($/bbl)       High($/bbl)         Average
----------------------------------------------------------------------------------------------------------------
11/29/99..................................................           26.2000           26.2400           26.2200
11/30/99..................................................           25.0400           25.0900           25.0650
12/01/99..................................................           25.4400           25.4800           25.4600
12/02/99..................................................           26.2000           26.3000           26.2500
12/03/99..................................................           26.5500           26.6000           26.5750
12/06/99..................................................           27.5000           27.5200           27.5100
12/07/99..................................................           26.9500           27.0000           26.9750
12/08/99..................................................           27.2000           27.2500           27.2250
12/09/99..................................................           26.7500           26.7900           26.7700
12/10/99..................................................           25.9000           26.0300           25.9650
12/13/99..................................................           25.7700           25.8000           25.7850
12/14/99..................................................           26.2000           26.2500           26.2250
12/15/99..................................................           26.8000           26.9500           26.8750
12/16/99..................................................           27.2500           27.3300           27.2900
12/17/99..................................................           26.3900           26.4500           26.4200
12/20/99..................................................           25.9000           26.0200           25.9600
12/21/99..................................................           25.7500           25.8500           25.8000
12/22/99..................................................           25.5000           25.5500           25.5250
12/23/99..................................................           25.9500           26.0000           25.9750
    Average...............................................           26.2758           26.3421           26.3089
----------------------------------------------------------------------------------------------------------------


[[Page 14068]]

    At the January 2000 workshops, one commenter suggested that MMS 
offer an option to use the market center where exchanges of the 
lessee's oil typically take place, rather than the market center 
nearest the lease. As explained above, we have not adopted this 
suggestion because our intent is to correlate both proximity to the 
lease and quality similarity. The commenter's suggestion would 
introduce unwarranted ambiguity and susceptibility to manipulation into 
the rule.
    You must calculate the daily mean spot price by averaging the daily 
high and low prices for the month in the selected publication. You must 
use only the days and corresponding spot prices for which such prices 
are published. You must adjust the value for applicable location and 
quality differentials, and you may adjust it for transportation costs, 
under Sec. 206.112 of this subpart.
    As explained in the December 1999 proposal, MMS changed 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 compared to spot 
prices, it nearly duplicates those spot prices. Second, application of 
spot prices removes 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 did not adopt any of the alternatives here (or for California 
and Alaska) that it did for the RMR where oil cannot be valued under 
Sec. 206.102. That is because, unlike the RMR, there are meaningful 
published spot prices applicable to production in the other regions 
(Cushing, Oklahoma; St. James, Louisiana; Empire, Louisiana; Midland, 
Texas; Los Angeles/San Francisco, California). In the United States, 
with the exception of the RMR, 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 RMR. 
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. 
MMS is not allowing the costs of marketing production as a deduction 
from value based on index prices or value 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(i) 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 final rule. The 
rule, in Sec. 206.106 discussed below, simply makes the longstanding 
implied obligation express.
    Paragraph 206.103(d) is paragraph 206.102(c)(3) of the January 1997 
proposal with minor clarifying word changes proposed in December 1999. 
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 will exercise the Secretary's authority to establish 
value based on other relevant matters. These could include, for 
example, well-established market basket price formulas.
    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 may 
apply to the MMS Director for approval to use a value representing the 
market at the refinery. Based on the lack of persuasive contrary 
comments on this provision, which was included in the February 1998 
proposal, we included it in the December 1999 proposal and in this 
final rule with only minor clarifying changes.

Section 206.104 What Index Price Publications Are Acceptable to MMS?

    Section 206.104 in the December 1999 proposal and in the final rule 
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 MMS accepts. We have included this section in this final 
rule unchanged. MMS will 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?

    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 are 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?

    Section 206.106 is paragraph 206.102(e)(1) of the January 1997 
proposal with minor clarifying word changes proposed in December 1999. 
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 unless otherwise provided in the lease agreement. As 
explained previously, 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. MMS disagrees with those 
arguments and is not altering the lessee's obligation to market 
production at no cost to the lessor in this final rule.
    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 the December 1999 proposal and have left it 
out of the final rule because these matters are already covered in 
other parts of MMS's regulations.

Section 206.107 How Do I Request a Value Determination?

    Section 206.107 of the February 1998 proposal included the 
substance of paragraph 206.102(f) of the January 1997 proposal in 
shortened and simplified terms. It said you may ask MMS for guidance in 
determining value, and you may propose a valuation method to

[[Page 14069]]

MMS. MMS would then review your proposal and provide you with a non-
binding determination of the guidance you request. We received a 
variety of comments that guidance alone is insufficient and that 
something much more substantial is needed to provide certainty and 
protection in case of audit.
    The final rule provides for value determinations issued by the 
Assistant Secretary for Land and Minerals Management that are binding 
on the lessee and MMS. It also provides for value determinations issued 
by MMS that are binding on MMS only and not the lessee, and that are 
not administratively appealable. See MMS's response to comments on the 
earlier proposals in Sections VI(f), VII(f), VIII(b), and IX(p) above.
    Also, we deleted paragraph 206.102(g) of the January 1997 proposal. 
It discussed audit procedures related to value determinations, and 
these are covered sufficiently in other parts of MMS's regulations.

Section 206.108 Does MMS Protect Information I Provide?

    Section 206.108 is paragraph 206.102(h) of the January 1997 
proposal, but with minor wording changes for clarity that we proposed 
in December 1999.

Section 206.109  When May I Take a Transportation Allowance in 
Determining Value?

    Section 206.109 includes the substance of Sec. 206.104 of the 
January 1997 proposal with only minor wording changes proposed in 
December 1999. In the December 1999 proposal and in this final rule, we 
removed the last two sentences of paragraph (a) of the January 1997 
proposal 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) 
continues the existing practice that you may ask MMS to approve a 
larger transportation allowance by demonstrating that your reasonable, 
actual, and necessary costs exceed the 50 percent limitation.

Sections 2206.110 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?

    Sections 206.110 and 206.111 of the December 1999 proposal were 
paragraphs 206.105(a) and (b), respectively, of the existing rule, 
rewritten to reflect plain English, with three proposed changes. MMS 
also requested comments on two other issues. Based on comments received 
and further analysis, we are making further changes in the final rule.
    The December 1999 proposal included 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. Section 206.111(g)(2) 
proposed in December 1999 stated 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. Under the proposed 
provision, if you or your affiliate purchased an existing 
transportation system at arm's length, your initial capital investment 
would have been equal to your purchase price of the transportation 
system.
    The final rule does not adopt the provision as proposed in December 
1999. As written, the December 1999 proposal gave rise to serious 
difficulties because of potential inflated allowances due to the 
original owner's ability to recover or ``recapture'' its actual costs 
by selling the pipeline at a value greater than the depreciable 
balance.
    For example, assume that an original owner had paid $20 million to 
construct a pipeline. Further assume that the original owner used a 20-
year straight-line depreciation and made no subsequent reinvestment. 
Further assume that in year 15, the original owner sold the pipeline at 
arm's length for $10 million to another person who also transported oil 
through the pipeline under a non-arm's-length arrangement. Under the 
December 1999 proposal, the purchaser would have begun a new 
depreciation schedule based on the $10 million purchase price. But the 
consequence of this transaction is that the original owner's actual 
transportation costs effectively were reduced because it recovered $5 
million of the $15 million it had taken as depreciation. Thus, if the 
actual transportation costs it originally reported were not 
recalculated, more transportation costs than were actually incurred 
would be deducted from royalty value.
    The December 1999 proposal thus gave rise to serious questions of 
how to ``recapture'' the royalties owed as a result of the reduced 
costs. One possible solution would have been to require the lessee who 
sold the transportation system to recalculate all of its transportation 
allowances for a retrospective period of several years. That would have 
been an extraordinarily complex calculation, because the difference 
between the transportation costs reported and the costs actually 
incurred is not equal to the amount of depreciation the selling lessee 
recaptured. If the depreciation element of the cost calculation were 
reduced retroactively, that also would change the calculation of return 
on undepreciated investment. Thus, the selling lessee would have to 
recalculate both elements of actual transportation costs for every 
report month. Further, this recalculation in most cases would involve a 
number of leases.
    In view of the complex and costly burdens that would be imposed on 
lessees, MMS has not provided for a detailed ``recapture'' procedure in 
the final rule. Instead, MMS adopted a simpler approach that still 
addresses much of the concern that led to the provision in the December 
1999 proposal.
    Under the final rule, if you or your affiliate own a transportation 
system on the effective date of the rule, you must base your 
depreciation schedule used in calculating actual transportation costs 
for royalties paid on production after the effective date of the rule 
on your total capital investment in the system. Total capital 
investment includes your original purchase price or construction cost 
and any subsequent reinvestment.
    If you or your affiliate were not the original owner of the system, 
but purchased the transportation system at arm's length before the 
effective date of the final rule, you must incorporate depreciation on 
the schedule based on your purchase price (and subsequent reinvestment) 
into your transportation allowance calculations in paying royalty on 
production after the effective date of the rule. However, you would 
begin at the point on the depreciation schedule corresponding to the 
effective date of the rule. You must prorate your depreciation for the 
year 2000 by claiming part-year depreciation for the period from the 
effective date of the rule until December 31, 2000.
    Under this provision, you may not adjust your transportation costs 
for

[[Page 14070]]

royalties paid on production before the effective date of the rule 
using the depreciation schedule based on your purchase price. The final 
rule does not permit recalculation of allowances for prior periods on 
that basis. Your calculation of actual transportation costs for periods 
before the effective date of the rule presumably was based on the 
original owner's depreciation schedule, and that will remain unchanged.
    For example, if you purchased a system at arm's length on January 
1, 1995, you would be in the sixth year of the depreciation schedule 
based on your purchase price. Assume that you had no subsequent 
reinvestment. You would incorporate into your calculation of actual 
transportation costs the depreciation applicable to the sixth year from 
the schedule based on your purchase price. However, you must prorate 
your claimed depreciation for calendar year 2000 by claiming part-year 
depreciation for the period from the effective date of the rule until 
December 31, 2000. If your calculation of actual transportation costs 
for the period before the effective date of the rule was based on the 
original owner's depreciation schedule, you may not adjust the 
calculation of costs for the period before the effective date of the 
rule using the schedule based on your purchase price.
    Under the final rule, if you are the original owner of the 
transportation system on the effective date of this rule, you must 
continue to use your existing depreciation schedule in calculating 
actual transportation costs for production in periods after the 
effective date of this section. In other words, your depreciation 
calculation does not change.
    However, if you or your affiliate purchase a transportation system 
at arm's length from the original owner after the effective date of the 
rule, you thereafter must base your depreciation schedule used in 
calculating actual transportation costs on your total capital 
investment in the system (including your original purchase price and 
subsequent reinvestment). You must prorate your depreciation for the 
year in which you or your affiliate purchased the system to reflect the 
portion of that year for which you or your affiliate own the system.
    If you or your affiliate purchase a transportation system at arm's 
length after the effective date of the rule from anyone other than the 
original owner, you must assume the depreciation schedule of the person 
who owned the system on the effective date of the rule.
    Thus, under the final rule, if you purchased a pipeline before the 
effective date of this rule (whether from the original owner or a 
subsequent owner), you now may calculate depreciation based on your 
purchase price. From now on, you may use your purchase price as your 
basis only if you purchase the pipeline from the original owner. If you 
purchase a pipeline from anyone other than the original owner, you will 
assume the seller's depreciation schedule. MMS believes that these 
provisions balance the competing considerations arising from the 
December 1999 proposal and minimize the burdens on both the lessees and 
the agency.
    The second change proposed in December 1999, at Sec. 206.111(g)(3) 
and adopted in the final rule as Sec. 206.111(j), provides 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 total capital investment in the transportation system multiplied 
by a rate of return under paragraph (h) of this section, regardless of 
the pipeline's depreciation status. (Under the current regulations a 
lessee is not allowed to claim any depreciation or return on capital 
once a pipeline is fully depreciated.) This is only to calculate the 
return component of the transportation allowance; you still must follow 
the depreciation schedule for calculating the depreciation component of 
the allowance. So while you are permitted to take a return component 
equal to the allowable rate of return times ten percent of the total 
capital investment each year after you have depreciated your facility 
to the ten percent level, you may claim only the actual depreciation 
according to the depreciation schedule. Thus, you will be eligible for 
a return component even when you can no longer claim depreciation.
    In the final rule, we also have added a clarifying paragraph (2) to 
specify that in calculating royalties paid on production after the 
effective date of the rule, you may apply this paragraph to a 
transportation system that before the effective date of this rule is 
depreciated at or below a value equal to ten percent of your total 
capital investment. You may not adjust royalties paid for production in 
periods before the effective date of the rule incorporating this 
additional return on investment component.
    Section 206.111(g)(4) of the December 1999 proposal (paragraph 
206.105(b)(2)(B) of the current regulations) provides an alternative 
for transportation facilities first placed in service after March 1, 
1988. In the December 1999 proposal, we asked for comments on whether 
this provision should be continued. In the final rule, we are deleting 
this paragraph. This paragraph is unnecessary in light of the changes 
we are making 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 
Sec. 206.157(b)(2)(v)). In the December 1999 proposal, we asked for 
comments on whether the existing rate of return should be changed. As 
noted above, some commenters suggested increasing the rate used in 
calculating the allowance to twice the Standard and Poor's BBB 
industrial bond rate. Two States and an individual commented that 
increasing the rate of return above the BBB rate is unnecessary and 
urged MMS to maintain the current rate of return.
    As explained above in Section IX(a), MMS believes the BBB bond rate 
is a very appropriate rate of return and is retaining it in the final 
rule.

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

    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. The December 1999 proposal 
eliminated the ``menu'' and instead combined the previously proposed 
Secs. 206.112 and 206.113 into one section that describes what 
adjustments apply when using index pricing. We have adopted that 
approach in the final rule. The ``menu'' of options is no longer 
necessary with the elimination of aggregation points and MMS-published 
differentials. This new paragraph covers all situations regardless of 
lease location, so there is no need for geographical breakdown of 
adjustments and allowances.
    As proposed in December 1999, we eliminated the location 
differential between the index pricing point and the market center. 
This is because under the valuation procedures proposed under the 
February 1998 and December 1999

[[Page 14071]]

proposals and adopted in this final rule, the index pricing point and 
market center are synonymous.
    Paragraph 206.112(a) covers situations where you dispose of your 
production under one or more arm's-length exchange agreements. In this 
case, you must 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 may 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 are 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 may not claim duplicate 
transportation costs.) A third adjustment (paragraph (d)) may 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 must 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 the production month. The value of Company A's 
production at the lease is $19.40 ($20.00--$0.10--$0.50) per barrel.
    Under paragraph 206.112(a), you must 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, separately determine the location/
quality differential under each of those exchange agreements, and 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, 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 must 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.
    Paragraph 206.112(b) addresses cases where your exchange agreement 
is not at arm's-length. In that event, you must request approval from 
MMS for any location/quality adjustment.
    Paragraph 206.112(c) addresses cases where you transport your 
production directly to a market center or to an alternate disposal 
point (for example, your refinery), and establish value based on index 
prices under Sec. 206.103.
    In the case of transportation directly to a refinery, you would 
deduct from the index price your actual costs of transporting 
production from the lease to the refinery with the costs determined 
under Secs. 206.110 or 206.111 and any quality adjustments determined 
by pipeline quality banks under paragraph 206.112(d). The index pricing 
point is the one nearest the lease.
    For example, a lessee or its affiliate in the Gulf of Mexico might 
transport its production directly to a refinery on the eastern coast of 
Texas and not to an index pricing point. Because that production is not 
sold at arm's length, the lessee must base value on the average of the 
daily mean spot prices for St. James, less actual costs of transporting 
the oil to the refinery and any quality adjustments from the lease to 
the refinery.
    Likewise, if a lessee or its affiliate transports Wyoming sour 
crude oil directly to its refinery in Salt Lake City, Utah, and values 
the oil based on paragraph 206.103(b)(3), the lessee must base value on 
the average of the daily Cushing spot prices, less the actual cost of 
transporting the oil to Salt Lake City and any quality adjustments 
between the lease and the refinery.
    When production is moved directly to a refinery and value must be 
established using an index, issues arise because the refinery generally 
is not located at an index pricing point. Consequently, the lessee does 
not incur actual costs to transport production to an index pricing 
point, and in any event, the production is not sold at arm's length at 
that point. The principle underlying the rules and cases granting 
allowances for transportation costs is that the lessee is not required 
to transport production to a market remote from the lease or field at 
its own expense. When the lessee sells production at a remote market, 
the costs of transporting to that market are deductible from value at 
that market to determine the value of the production at or near the 
lease. Where sales occur only at or near the lease, the question of a 
transportation allowance, as that term always has been understood, does 
not arise. However, because the lease and the index pricing point may 
be distant from one another, there is a difference in the value of the 
production between the index pricing point and the location of the 
lease. The question becomes how to determine or how best to approximate 
that difference in value.
    In theory, one solution would be for MMS to try to derive what it 
would cost a lessee to move production from the lease to the index 
pricing point. There are, in MMS's view, several problems with such an 
approach. First, it would require a burdensome information collection 
from industry and impose substantial information collection costs on 
many parties to whom the resulting calculation may never be relevant. 
Second, in many cases it may well not be possible to obtain information 
on which to base such a calculation. In many instances, it is likely 
that no production from the lease or field is transported to the index 
pricing point that applies under Sec. 206.103. Consequently, in such 
cases there would be no useful data on which such a cost derivation 
could be based.
    Another possible solution, in theory, would be for MMS to derive a 
location adjustment between the index pricing point and the refinery. 
This might be possible if, for example, there are arm's-length 
exchanges of significant volumes of oil between the index pricing point 
and the refinery, and if the exchange agreements provide for location 
adjustments that can be separated from quality adjustments. But 
establishing such location adjustments on any scale again would require 
a burdensome

[[Page 14072]]

information collection effort. MMS also anticipates that in many cases 
there would be no useful data from which to derive a location 
adjustment.
    As we explained in the December 1999 proposal, MMS therefore 
believes that the best and most practical proxy method for determining 
the difference in value between the lease and the index pricing point 
is to use the index price as value at the refinery, and then allow the 
lessee to deduct the actual costs of moving the production from the 
lease to the refinery. This is not a ``transportation allowance'' as 
that term is commonly understood, but rather is part of the methodology 
for determining the difference in value due to the location difference 
between the lease and the index pricing point. Nevertheless, it is 
appropriate to include this deduction for situations in which index 
pricing is used.
    MMS included this same method in the January 1997 proposal and did 
not receive any suggestions for alternative methods. We received few 
comments on this issue in response to the February 1998 proposal. 
However, one State commented that this method could result in 
calculation of inappropriate differentials. Absent better alternatives, 
MMS believes this method is the best and most reasonable way to 
calculate the differences in value due to location when production is 
not actually moved from the lease to an index pricing point.
    However, if a lessee believes that applying the index price nearest 
the lease to production moved directly to a refinery results in an 
unreasonable value based on circumstances of the lessee's production, 
paragraph 206.103(e) allows MMS to approve an alternative method if the 
lessee can demonstrate the market value at the refinery. Although we 
received a few comments that MMS should not allow such requests, MMS 
believes it should leave this opportunity open for those limited cases 
where the procedure discussed above may be shown to be inappropriate, 
as we explained in the December 1999 proposal. MMS will do a thorough 
review and analysis of any such requests and will only approve them 
where the proper alternative value or procedure has been clearly 
demonstrated.
    It is the lessee's burden to provide adequate documentation and 
evidence demonstrating the market value at the refinery. That evidence 
may include, but is not limited to: (1) costs of acquiring other crude 
oil at or for the refinery; (2) how adjustments for quality, location, 
and transportation were factored into the price paid for the other oil; 
(3) the volumes acquired for the refinery; and (4) other appropriate 
evidence or documentation that MMS requires. If MMS approves an 
alternative value representing market value at the refinery, there will 
be no deduction for the costs of transporting the oil to the refinery 
unless it is specifically identified in the Director's approval. 
Whether any quality adjustment is available depends on whether the oil 
passes through a pipeline quality bank or if an arm's-length exchange 
agreement used to get oil to the refinery contains a separately-
identifiable quality adjustment.
    Paragraph 206.112(c) also covers situations where you transport 
your oil directly to an MMS-identified market center. To arrive at the 
royalty value, you would adjust the index price by your actual costs of 
transportation under Secs. 206.110 and 206.111. A second adjustment 
(paragraph (d)) may be warranted if the quality of your lease 
production differs from the quality of the oil at the market center. 
This adjustment would be based on pipeline quality bank premia or 
penalties, but only if such quality banks exist at the aggregation 
point or intermediate commingling points before your oil reaches the 
market center.
    For example, Company A transports its production from a platform in 
the Gulf of Mexico to St. James, Louisiana, under a non-arm's-length 
transportation contract with its affiliate. The actual cost of 
transporting production under Sec. 206.111 is $0.50 per barrel. The 
average of the daily spot prices at St. James is $20.00 per barrel for 
the production month. The value of Company A's production at the lease 
is $19.50 ($20.00-$0.50) per barrel.
    As discussed earlier in this preamble, MMS received a variety of 
comments, pro and con, about the differentials used in Sec. 206.112. 
MMS believes the criteria laid out in this final rule are fair and 
reasonable and best represent a balanced response to the comments 
received.
    In this final rule, paragraph 206.112(e) contains language from 
proposed paragraph 206.112(f) of the February 1998. It states that the 
term ``market center'' means Cushing, Oklahoma, when determining 
location/quality differentials and transportation allowances for 
production from leases in the RMR.
    In the February 1998 proposal at paragraph 206.112(e), and in the 
December 1999 proposal and the final rule at paragraph 206.112(d), MMS 
added a separate adjustment to reflect quality differences based on 
quality banks between your lease and an alternate disposal point or 
market center applicable to your lease. You would make these quality 
adjustments according to the pipeline quality bank specifications and 
related premia or penalties that may apply in your specific situation. 
If no pipeline quality bank applies to your production, then you would 
not take this quality adjustment. Likewise, if a quality adjustment is 
already contained in an arm's-length exchange agreement from the lease 
to the market center, you could not also claim a pipeline quality bank 
adjustment from the lease to the aggregation point or market center. 
MMS believes this additional adjustment would more accurately reflect 
actual quality adjustments made by buyers and sellers.
    In this final rule we added a new paragraph 206.112(g) to clarify 
that regardless of how you dispose of your production and which 
adjustments might otherwise apply, you cannot include separate 
transportation or quality adjustments that duplicate one another. That 
is, any time you take one of the listed adjustments, you cannot 
duplicate any portion of that adjustment in part or all of any other 
adjustment that otherwise would be allowable.
    Paragraph 206.112(f) of the December 1999 proposal and of this 
final rule addresses situations where you may not have access to 
differentials between the lease and the alternate disposal point or 
market, or you may not have access to the actual transportation costs 
from the lease alternate disposal point or market center. In such 
cases, which should be infrequent, MMS will permit you to request 
approval for a transportation allowance or quality adjustment. In 
determining the allowance for transportation from the lease to the 
alternate disposal point or market center, MMS will look to 
transportation costs and quality adjustments reported for other oil 
production in the same field or area, or to available information for 
similar transportation situations. Under paragraph 206.112(b), you must 
also request approval from MMS for any location/quality adjustments 
when you have a non-arm's-length exchange agreement.
    As discussed above, paragraph (g) of Sec. 206.112 of the December 
1999 proposal and the final rule clarifies that you may not use any 
transportation or quality adjustment that duplicates all or any part of 
any adjustment that you use under this section.

Section 206.113 How will MMS identify market centers?

    Section 206.113 of the December 1999 proposal and the final rule is 
paragraph 206.105(c)(8) of the 1997 proposal and

[[Page 14073]]

Sec. 206.115 of the February 1998 proposal, except that we have 
eliminated the identification of aggregation points and we have made 
minor wording changes. MMS has eliminated the list of aggregation 
points identified in the January 1997 proposal in conjunction with the 
elimination of Form MMS-4415.
    In the preamble to the January 1997 proposal, MMS listed market 
centers for purposes of the rule. That list included Guernsey, Wyoming. 
MMS has eliminated Guernsey as a market center for the reasons given 
earlier. Also, we received comments that simply using Los Angeles and 
San Francisco as market centers for ANS pricing purposes was too broad 
and that multiple, local delivery points in and near these two cities 
should be included in the market center definition. So, for purposes of 
this rulemaking, the Los Angeles market center includes Hines Station, 
GATX Terminal, and any of the refineries located in Los Angeles County. 
The San Francisco market center includes Avon, or any of the refineries 
located in Contra Costa or Solano Counties.

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

    Section 206.114 of the December 1999 proposal and the final rule is 
paragraph 206.105(c)(1) of the existing rule rewritten in plain 
English.

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

    Section 206.115 of the December 1999 proposal and the final rule is 
paragraph 206.105(c)(2) of the existing rule rewritten in plain 
English, except paragraph 206.105(c)(2)(iv) is deleted as described in 
the preamble to the January 1997 proposal. We also added a sentence 
clarifying that when you adjust your estimated allowance to an actual 
allowance, Sec. 206.117 will apply.

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

    Section 206.116 of the December 1999 proposal and the final rule is 
paragraph 206.105(d) of the existing rule rewritten in plain English.

Section 206.117  What reporting adjustments must I make for 
transportation allowances?

    Section 206.117 of the December 1999 proposal and the final rule is 
paragraph 206.105(e) of the existing rule rewritten in plain English.

Section 206.118  Are costs allowed for actual or theoretical losses?

    Section 206.118 of the December 1999 proposal and the final rule is 
paragraph 206.105(f) of the existing rule rewritten in plain English. 
Reference to the FERC-or State regulatory agency-approved tariffs was 
deleted in the January 1997 proposal, and since this final rule does 
not provide the option for lessees who own pipelines to request use of 
such tariffs in lieu of their actual costs, the tariff reference is not 
in this final rule. Although we received a comment that actual or 
theoretical losses are real costs of transportation, this section is 
simply a continuation of longstanding policy.

Section 206.119  How are the royalty quantity and quality determined?

    Section 206.119 of the December 1999 proposal and the final rule is 
Sec. 206.103 of the existing rule rewritten in plain English.

Section 206.120  How are operating allowances determined?

    Section 206.120 of the December 1999 proposal and the final rule is 
Sec. 206.106 of the existing rule rewritten in plain English.

Section 206.121.  Is there any grace period for reporting and paying 
royalties after this subpart becomes effective?

    In the January 2000 public workshops, some commenters discussed the 
need for systems changes in their companies to comply with certain 
provisions of the December 1999 proposal. In the final rule, we have 
added a new Sec. 206.121 in an effort to facilitate that transition. 
Under this section, you may adjust royalties reported and paid for the 
first three production months after the effective date of this rule 
without liability for late payment interest if the adjustment results 
from systems changes needed to comply with new requirements imposed 
under this subpart that were not requirements under the predecessor 
rule. This is not a blanket exemption from late payment charges. The 
lessee will bear the burden of being able to demonstrate that the 
adjustment resulted from a systems change necessitated by the final 
rule. While the lessee may be billed for interest, it will be credited 
only if MMS is satisfied that the adjustment that caused the interest 
bill was due to systems changes needed as a result of this rule.

Decision to delete proposed change to royalty-in-kind procedures at 30 
CFR 208.4(b)(2)

    In the January 1997 proposal, MMS proposed to modify the procedures 
for determining the sales price billed to the RIK purchaser. The 
proposal would have used the index price less a location/quality 
differential specified in the RIK contract. MMS has decided not to 
proceed with this approach. Instead, MMS will establish future RIK 
pricing terms directly within the contracts it writes with RIK program 
participants. MMS's goal still is to achieve pricing certainty in RIK 
transactions. But because of its revised plans, MMS has dropped its 
proposed January 1997 change to 30 CFR 208.4(b)(2).

XI. Procedural Matters

General Comments Relating to Procedural Matters for the December 1999 
Proposal

    With respect to the procedural matters of this proposed rule, MMS 
received comments from several parties, including U.S. Senators, with 
the most detailed comments coming from one entity (the Barents Group). 
Many industry groups endorsed the Barents Group's comments. We received 
no comments related to procedural matters from States, watchdog groups, 
or private citizens.
    The comments generally were focused on the burden estimates 
associated with implementing the rule. We will address the comments in 
the sections that discuss the respective requirements.

General Comments Relating to Procedural Matters for the February 1998 
Proposal

    MMS received comments regarding various procedural matters involved 
in the February 1998 proposed rule from one entity (The Barents Group) 
that were endorsed by several companies and industry organizations. One 
comment centered on overall procedure, while two other comments 
specifically addressed Executive Order (E.O.) 12866 and the Regulatory 
Flexibility Act. We will address the overall procedure comment here, 
and we will address the specific comments in the sections that discuss 
the respective requirements.

Issue: Procedures not followed with the latest publication and re-
opening of the comment period

    Summary of Comments: The commenter believes that the Administrative 
Procedure Act (APA) requires any comment period to remain open for at 
least 60 days. Furthermore, an advance copy of the rule (in this case 
the July 1998 proposal) should be sent to the Office of Management and 
Budget (OMB) for review prior to any publication. The comment period 
for this rule was much less than 60 days

[[Page 14074]]

and OMB never received a copy of the rule.
    MMS Response: The APA does not specify a minimum time period for 
accepting comments. The APA only requires a ``reasonable'' comment 
period depending on the particular facts of the rule. Generally, the 
comment period is 60 days for proposed rules, and shorter periods for 
supplementary proposed rules. The July 1998 proposal was not an initial 
proposed rule; it was a further supplementary proposed rule 
representing the fifth in a series of proposed and supplementary 
proposed rules. Given the numerous times this rule has been published 
for comment and the many meetings held over the last three-plus years, 
MMS believes the brief comment period (July 9 through July 31) for the 
July 1998 proposal, which merely addressed issues that had been 
commented on before, was more than adequate. The July 1998 proposal 
included few changes to previous versions of the rule; the major 
substance of the rule had been addressed several times in great detail. 
Additionally, MMS provided OMB a copy of the February 1998 proposal, 
and OMB approved the rule for publication. MMS made only minor 
modifications to the February 1998 proposal in its July 1998 proposal, 
and MMS provided a copy of the July 1998 proposal to OMB.

The Regulatory Flexibility Act

    The Department certifies that this rule will not have a significant 
economic effect on a substantial number of small entities under the 
Regulatory Flexibility Act (5 U.S.C. 601 et seq.).
    This rule establishes the methodology royalty payors are to use in 
calculating royalty payments owed the Federal Government for oil 
produced on Federal leases, both onshore and offshore. There are 
approximately 800 such royalty payors.
    The majority of royalty payors operate onshore and are smaller 
companies that sell the oil they produce to third parties in arm's-
length transactions. They generally do not engage in downstream 
petroleum businesses. Larger companies usually operate offshore as well 
as onshore and have the resources needed to meet the technical and 
financial challenges associated with producing oil on the Outer 
Continental Shelf, especially in deep water. Many of these larger firms 
are integrated companies that produce crude oil, operate refineries, or 
market petroleum products at the wholesale and retail levels.
    This rule provides that lessees that sell their oil under arm's-
length transactions will continue to report and pay royalties based on 
their gross proceeds. Consequently, this rule will not affect the 
amount of royalties they pay, nor the manner in which they calculate 
the royalty. Generally, only integrated payors who do not trade oil at 
arm's-length will be required to pay royalties based on the rule's non-
arm's-length provisions.
    According to the Small Business Administration (SBA), drilling 
companies and companies that extract oil, gas or natural gas liquids 
having fewer than 500 employees are defined as small businesses. SBA 
defines refining companies as small if they employ less than 1,500 
people. Based on the 500-employee standard for oil extraction 
companies, we estimate that over 90 percent (or about 740) of the 800 
royalty payors, are small businesses.
    MMS's analysis of 1998 data shows that a total of 45 royalty payors 
would have been required to value their production as less than arm's-
length for royalty purposes. The other 755 companies sold the oil they 
produced under arm's length transactions and would not be affected by 
this rule. In comparison to their actual royalty payments, MMS 
estimates that the 45 affected payors would have paid additional 
royalties totaling $67.3 million.
    Using company employment data, we determined that nine of the 45 
companies are small businesses. (Since these companies are refiners as 
well as producers, we used the SBA standard of 1,500 or fewer employees 
for determining which companies were small.) Consequently, the nine 
small businesses who will be affected by the rule represent only 1.2 
percent of the 740 small businesses who pay royalties on Federal oil. 
Our analysis of these nine companies' 1998 royalty payment data 
indicates that they would have paid additional royalties of 
approximately $280,000 or an average of about $31,100 each in 1998.
    In addition to the impact on royalty payments, the rule will impose 
certain paperwork burdens as discussed in the Paperwork Reduction Act 
section of this preamble. Our analysis of the additional reporting 
burden for small companies required by this rule is 31.25 hours per 
company. Based on a cost of $50 per hour, the total cost to the nine 
affected small companies is about $14,000, or an average of about 
$1,600 per company.
    In summary, nine small businesses will be affected economically by 
this rule. Their costs will include about $280,000 in additional 
royalties and $14,000 in reporting burdens for a total cost of 
$294,000. On average, the cost per company is about $32,700 annually 
($31,100 in additional royalties and $1,600 in reporting burden).
    Given the small number of companies and the costs involved, this 
rule will have minimal impact on companies producing oil on Federal 
lands, including the 45 royalty payors most directly affected. As 
noted, most of these companies are large integrated oil companies with 
very substantial technical, financial and real property resources. The 
additional costs that may result from the rule are small when compared 
to the revenues the companies earn from the oil they produce from 
Federal leases and upon which royalties are paid. As discussed in the 
economic analysis, the benefits of pricing simplification and the 
savings associated with transportation allowance changes would outweigh 
any additional administrative costs associated with this proposed rule. 
This analysis is available upon request.
    Because of the lack of a substantial direct impact on the producing 
companies, the rule will have no secondary impacts on small businesses, 
such as oil field service companies, supply boat operators, etc., that 
conduct business with the producing companies.
    Consequently, MMS concludes that this rule will not have a 
significant impact on a substantial number of small business entities.
    Summary of Comments Related to the December 1999 Proposal:
    One party commented that all small businesses will be affected by 
the rule, not just the nine businesses MMS identifies. Many 
independents have marketing affiliates and also act as designees on 
behalf of other lessees. These aspects were not considered in MMS's 
analysis.
    MMS Response: MMS has maintained throughout this rulemaking that 
lessees who sell their oil at arm's length will continue to report and 
pay on their gross proceeds. Almost all of the identified small 
businesses dispose of their production through arm's-length contracts. 
Further, small businesses who market through an affiliate may report 
and pay on the affiliate's arm's-length gross proceeds.
    Lessees that have designees reporting for them will incur no 
additional burden, while the designees themselves likely will not 
either. In the majority of cases, lessees who have designees reporting 
on their behalf are smaller firms whose gross proceeds from arm's-
length sales will be the reported royalty value. In these cases, small 
companies with interests in Federal leases would rather dispose of 
production at arm's length and allow a designee to report for them. The 
rule imposes no additional

[[Page 14075]]

burden in these cases. MMS therefore does not believe that the rule 
will impose significant burdens on all small businesses.
    Summary of Comments Related to the July 1998 Proposal: MMS received 
one comment on the July 1998 proposal. The comment and MMS's response 
follow.
    Summary of Comments: MMS has not met the requirements of the 
Regulatory Flexibility Act because the rule does significantly impact 
small businesses.
    MMS Response: As stated below, our analysis concludes that the 
requirements of this final rule will not significantly impact a 
substantial number of small businesses. In general, only integrated 
payors with either a refinery, a separate marketing entity, or both 
will pay additional royalties. Such lessees are typically larger in 
size and able to absorb any additional burden (however small) the rule 
may impose. In the few cases where small businesses may be affected, 
the impact will be minimal.

Small Business Regulatory Enforcement Fairness Act (SBREFA)

    This final rule is not a major rule under 5 U.S.C. 804(2), the 
Small Business Regulatory Enforcement Fairness Act. This rule:
    (a) Will not have an annual effect on the economy of $100 million 
or more;
    (b) Will not cause a major increase in costs or prices for 
consumers, individual industries, Federal, State, or local government 
agencies, or geographic regions; and
    (c) Will not have significant adverse effects on competition, 
employment, investment, productivity, innovation, or the ability of 
U.S.-based enterprises to compete with foreign-based enterprises.
    See the Executive Order 12866 analysis later in this preamble for 
specific estimated effects of the rule.

Unfunded Mandates Reform Act of 1995

    The Department of the Interior has determined and certifies 
according to the Unfunded Mandates Reform Act, 2 U.S.C. Sec. 1531 et 
seq., that this rule will not impose a cost of $100 million or more in 
any given year on local, tribal, or State governments, or the private 
sector. This rule will not change the relationship between MMS and 
State, local, or tribal governments. The historical relationship 
between MMS and State and local governments will not change in any way. 
The rule will, in fact, increase State royalty revenues without 
imposing additional costs. A statement containing the information 
required by the Unfunded Mandates Reform Act (2 U.S.C. 1531 et seq.) is 
not required.
    See the Executive Order 12866 analysis later in this preamble for 
specific estimated effects of the rule.

Fairness Board and National Ombudsman Program

    The Small Business and Agriculture Regulatory Enforcement Ombudsman 
and 10 regional fairness boards were established to receive comments 
from small businesses about Federal agency enforcement actions. The 
Ombudsman will annually evaluate the enforcement activities and rate 
each agency's responsiveness to small businesses. If you wish to 
comment on the enforcement actions of MMS, call 1-888-734-3247.

Executive Order 13132 (Federalism)

    In accordance with Executive Order 13132, this final rule does not 
have Federalism implications. This rule does not substantially and 
directly affect the relationship between the Federal and State 
governments. This final rule does not negatively affect the States' 
prerogatives regarding oil valuation or their share of oil royalty 
receipts. The affected States were heavily involved in the rulemaking 
process through their continued participation in MMS's numerous public 
workshops and submission of detailed comments at every stage of this 
lengthy rulemaking process.
    The management of Federal leases is the responsibility of the 
Secretary of the Interior. Royalties collected from Federal leases are 
shared with State governments on a percentage basis as prescribed by 
law. This final rule does not alter any lease management or royalty 
sharing provisions. It determines the value of production for royalty 
computation purposes only. This final rule does not impose costs on 
States or localities. Costs associated with the management, collection 
and distribution of royalties to States and localities are currently 
shared on a revenue receipt basis. This final rule does not alter that 
relationship.

Executive Order 12630

    The Department certifies that this rule does not represent a 
governmental action capable of interference with constitutionally 
protected property rights. Thus, a Takings Implication Assessment need 
not be prepared under Executive Order 12630, Governmental Actions and 
Interference with Constitutionally Protected Property Rights.
    Summary of Comments Related to the February 1998 and December 1999 
Proposals: The proposed rule deprives lessees of their constitutionally 
protected property rights when royalties are paid based on a higher 
than actual lease sales price. This is a price that the lessee would 
find impossible to actually realize because it includes returns on 
investments and on downstream marketing profits. The commenter asserted 
that because such a taking will occur if the rule is approved, MMS must 
prepare a Takings Implication Assessment pursuant to Executive Order 
12630.
    MMS Response: Executive Order 12630 requires a Federal agency to 
justly compensate a private property owner if private property is taken 
for public use. Disagreements over methods of valuing production for 
royalty purposes do not change the property relationship between a 
lessee and the Federal lessor, and do not operate to deprive the lessee 
of any property interest. Even if a particular valuation method is held 
to be unlawful or unauthorized, the remedy is to overturn the 
unauthorized agency action. This does not have constitutional takings 
implications.

Executive Order 12866

    The Office of Management and Budget (OMB) determined that this rule 
is a significant rule under Executive Order 12866 Section 3(f)(4). 
Although we estimate that the rule will have an effect less than $100 
million on the economy, this order states that a rule is considered a 
significant regulatory action if it ``raises novel legal or policy 
issues arising out of legal mandates, the President's priorities, or 
the principles set forth in this Executive Order.'' OMB determined that 
this rule raises novel legal or policy issues.
    MMS met the Executive Order 12866 regulatory compliance and review 
requirements when it developed its February 1998 proposal. MMS's 
analysis of the revisions it made to the February 1998 proposal 
indicated those changes would not have a significant economic effect, 
as defined by Section 3(f)(1) of this Executive Order.
    This rule will not adversely affect in a material way the economy, 
productivity, competition, jobs, the environment, public health or 
safety, or State, local, or tribal governments or communities. In its 
February 1998 proposal, MMS's analysis of 1996 data estimated that the 
rule would have had an economic impact of approximately $66 million in 
increased royalty collections annually. Because a substantial period of 
time elapsed since the initial analysis, MMS has performed a similar 
analysis comparing actual 1998 royalties paid with those we estimate 
would have been required had

[[Page 14076]]

this rule been in effect. This recent analysis showed the rule would 
have had an economic impact of approximately $67 million in increased 
royalty collections annually, or about the same impact estimated 
earlier.
    MMS completed a Record of Compliance (ROC), an internal document 
that was not published in the Federal Register, in conjunction with the 
December 1999 proposed rule. The conclusions that we reached in the ROC 
continue to apply to this final rule. The ROC contains the detailed 
analysis required under Executive Order 12866. Also, we present the 
economic analysis of this rule's impacts later in this section.
    This rule will not create a serious inconsistency or otherwise 
interfere with an action taken or planned by another agency. We are not 
aware of any actions taken or planned by other agencies, State or 
Federal, that are similar to this one or that this rule would interfere 
with.
    This rule does not alter the budgetary effects of entitlements, 
grants, user fees, or loan programs or the rights or obligations of 
their recipients.
    As part of the procedural matters associated with the December 
1999, July 1998, and February 1998 proposals, MMS accepted comments on 
the specific approach, assumptions, and methodology used in the 
Executive Order 12866 analysis. For the December 1999 proposal, MMS 
received detailed comments from groups representing industry, producing 
companies and a Senate group. For the February 1998 proposal, MMS 
received a detailed report from one commenter and comments from two 
other organizations regarding the analysis. For the July 1998 proposal, 
MMS received one comment (from the Barents Group). MMS's responses to 
all of those comments follow. MMS did not receive any additional 
comments on the Procedural Matters in response to the March 1999 
notice.
    Comments Related to the December 1999 Proposal:

(a) Necessity of E.O. 12866 Analysis

    Summary of Comments: One party commented that MMS is required to 
perform an analysis under Executive Order 12866 because this rule 
raises novel legal requirements. Further, this analysis requires a 
complete examination of all feasible alternatives. MMS has not 
completed this required analysis.
    MMS Response: MMS completed a ROC, an internal document that was 
not published in the Federal Register, in conjunction with the December 
1999 proposed rule. The conclusions that we reached in the ROC continue 
to apply to this final rule. The ROC contains the same detailed 
analysis required under Executive Order 12866. Additionally, we 
examined alternatives in detail over the entirety of this four-plus 
year rulemaking process. See the discussion of alternatives after the 
same comment was presented in response to the February 1998 proposed 
rulemaking.
    The Office of Management and Budget determined this rule is a 
significant rule under Executive Order 12866 Section 3(f)(4). This 
order states that a rule is considered a significant regulatory action 
if it ``raises novel legal or policy issues arising out of legal 
mandates, the President's priorities, or the principles set forth in 
this Executive Order.'' MMS met the Executive Order 12866 regulatory 
compliance and review requirements when it developed its February 1998 
proposal.
    MMS's analysis of the revisions it made to the February 1998 
proposal indicated those changes would not have a significant economic 
effect, as defined by Section 3(f)(1) of this Executive Order.
    In its February 1998 proposal, MMS's analysis of 1996 data showed 
the rule would have had an economic impact of approximately $66 million 
in increased royalty collections annually. This estimate was based on a 
comparison of Federal oil royalties received in 1996 for both onshore 
and offshore production to those we would have expected under the 
provisions of the February 1998 proposal. Since the proposal used 
separate valuation methodologies for three geographic areas, so did the 
analysis. Because a substantial period of time elapsed since the 
initial analysis, MMS has performed a similar analysis comparing actual 
1998 royalties paid with those we estimate would have been required had 
this rule been in effect.

(b) The Analysis Does Not Account for Designee Payors

    Summary of Comments: Payors who pay on behalf of lessees will pass 
the incremental cost of a royalty increase on to their lessees. This 
cost is not accounted for.
    MMS Response: MMS does not anticipate significant additional costs 
associated with payors who pay on behalf of lessees. See discussion 
above in the Regulatory Flexibility Act section.

(c) General Compliance with and Understanding of Rule

    Summary of Comments: The rule is not clear in some respects. 
Companies will have to incur additional expense for training on how to 
comply with the rule.
    MMS Response: Although the rule departs from the current royalty 
valuation methods for oil not sold at arm's length, MMS believes the 
rule is actually easier to understand and comply with. The rule 
reflects the way oil is bought and sold in the marketplace today. MMS 
believes that many industry professionals are familiar with the terms 
and methodology used in this rule. We agree that as with any new rule, 
there will be an adjustment period as lessees review the rule, analyze 
its application to their business, and implement its requirements. 
However, we do not believe this will be a significant cost.
    MMS also intends to provide payor training in several locations 
after the publication of the final rule. Additionally, MMS will revise 
the Payor Handbook.

(d) Revision of Lessees' Computer Systems

    Summary of Comments: Several parties are concerned that the 
proposed rule will necessitate a change in the computer systems already 
in place for paying royalty under the current regulations.
    MMS Response: We received this comment in response to the February 
1998 proposal. See our response below. None of these comments have 
explained how any necessary computer systems changes cause the rule to 
be inconsistent with Executive Order 12866.

(e) Burden Associated With Two-Year Election Requirement

    Summary of Comments: We received a comment that there are 
significant internal evaluation costs associated with electing 
valuation methods every 2 years.
    MMS Response: Internal economic decisions regarding the disposition 
of oil and what alternatives are financially beneficial to a lessee are 
a necessary part of a lessee's business. We do not believe that 
evaluating whether to value oil on the basis of gross proceeds or index 
for a property once every 2 years, in cases to which Sec. 206.102(d) 
applies, is an onerous or difficult decision. Moreover, a lessee does 
not have to undertake the analysis to decide which method to elect if 
it does not want to; arm's-length gross proceeds is the primary measure 
of value in these cases.

(f) Differentials

    Summary of Comments: One commenter asserted that additional costs 
will be incurred that MMS did not

[[Page 14077]]

estimate for ``choosing and maintaining the acceptable recommendations 
for quality, location, and transportation differentials, and indexing 
methodology.''
    MMS Response: Although we do not fully understand the comment, we 
did address the costs a company will incur to compute its own 
differentials.

(g) Affiliation Determinations

    Summary of Comments: MMS did not account for the costs associated 
with companies asking MMS to determine if they are affiliated.
    MMS Response: MMS believes that submitting facts relevant to 
determining if two persons are affiliated within the meaning of this 
rule is a straightforward and uncomplicated process and does not entail 
significant costs. MMS does not believe that submission of facts or 
documents for this purpose creates any inconsistency with Executive 
Order 12866.

(h) Audit Costs

    Summary of Comments: MMS claims that the current audit burden will 
be reduced because the rule is simpler to comply with. All MMS is doing 
is replacing one audit cost for another because there is so much 
uncertainty in the rule. MMS does not provide enough specifics in the 
rule for a complete level of understanding.
    MMS Response: MMS believes that the rule is understandable and that 
lessees should have all the elements necessary for proper valuation at 
its disposal. MMS believes this rule is more objective than some 
provisions in the predecessor rule. While any rule involves audit 
costs, MMS believes that this rule will reduce the overall audit 
burden.

(i) Requests for Valuation Determinations

    Summary of Comments: MMS underestimates the number of 
determinations industry will request. The rule is so complex and 
uncertain that many companies will be requesting determinations.
    MMS Response: MMS believes that the number of value determinations 
under Sec. 206.107 of the final rule should be about the same as under 
the current rule, and they should be no more complex. We also believe 
that the number of other requests related to location and quality 
differentials should be less than or equal to the number we receive 
under the existing provisions concerning exceptions to computing actual 
costs of transportation. Additionally, MMS intends to provide ample 
payor training sessions and a revision of the Payor Handbook. We also 
added more examples to the preamble at industry's request to clarify 
how various provisions apply.

(j) Actual Transportation Cost Calculations

    Summary of Comments: MMS does not address the burden of requiring a 
computation of ``actual costs'' as a result of disallowing FERC tariffs 
in non-arm's-length transportation arrangements. One industry commenter 
expressed concern about providing records to MMS.
    MMS Response: We believe the burden estimates associated with the 
current approved Information Collection Request for Form MMS-2014 (OMB 
Control Number 1010-0022) already account for the task of computing 
non-arm's length transportation allowances as provided in the 1988 
regulations. This allowance is based on a company's (or its affiliated 
pipeline's) actual costs of capital investment and operating and 
maintenance expenses.
    That allowance calculation is based on the formula (D+R+E)/T, where 
D=annual depreciation of the pipeline's capital investment, R=return on 
undepreciated capital investment (the amount left each year after that 
year's depreciation has been deducted), E=annual operating and 
maintenance expenses, and T=the throughput volume of the pipeline.
    While companies in the past may have been using FERC tariffs in 
lieu of this formula, we believe this cost information is readily 
available to the companies even in situations where an affiliate is 
involved. Additionally, we believe this calculation is relatively 
straightforward. While more lessees will have to calculate actual costs 
under this rule because it disallows FERC tariffs, the burden of 
calculating actual costs in each case has not changed substantially. 
Moreover, under the existing rules MMS has disallowed use of many FERC 
tariffs because FERC no longer ``approves'' tariffs for pipelines over 
which it has no jurisdiction.
    The comment that these records must be sent to MMS is not accurate. 
We do not require lessees to submit this information initially for 
review (except in cases where lessees ask to exceed the presumptive 
allowance limits). We do, however, require that all information be 
available for audit. This is no different than the records maintenance 
requirement under the current regulations.

(k) MMS's Economic Analysis Understates Overall Costs

    Summary of Comments: Several companies and industry groups 
expressed concern that MMS has underestimated the full impact of the 
rule. Many costs such as compliance, training, and the filing of 
additional guidance requests are not addressed. MMS claims of legal 
savings associated with the rule are not accurate because additional 
legal costs will be incurred in other areas.
    MMS Response: MMS has attempted to categorize and accurately 
estimate all costs associated with the proposed rulemaking. Specific 
types of costs that commenters alleged that MMS did not take into 
account are discussed in other paragraphs of this section.
    For the analysis associated with the December 1999 proposed rule, 
we did address and estimate the costs associated with compliance and 
filing of guidance requests. Determining the exact impact of these 
costs is very difficult and will vary for every organization affected 
by the rule. Our estimates attempt to categorize the average impact on 
an average payor affected by the rule. Some companies will spend more 
than others. Our estimates were intended to provide a general impact of 
the proposed rule.
    Further, we have had discussions with OMB about our estimated 
impacts of the rule. OMB believes that our estimated impact analysis is 
sufficient and conforms with OMB requirements.

(l) MMS Fails to Account for Significant Costs to Small Businesses

    Summary of Comments: Some commenters believe MMS fails to 
adequately address the impact on small businesses. The rule will affect 
all payors, not just a handful of major producers as MMS claims. Many 
small businesses have affiliates who will be forced to pay on the 
proposed index methodology.
    MMS Response: MMS continues to believe this rule will not affect a 
substantial number of small businesses because we anticipate that most 
small businesses will continue to pay royalties based on their arm's-
length gross proceeds, as they do under the current regulations. 
Approximately 800 businesses pay royalties to MMS on oil produced from 
Federal leases. MMS believes approximately 45 of the 800 total payors 
are likely to pay significant additional royalties under this rule. (We 
believe that most small businesses with affiliate sales will report the 
affiliate's arm's-length gross proceeds as value. Only small businesses 
with refinery

[[Page 14078]]

capability that do not sell oil at arm's length will be affected 
substantially by the rule.) We further believe that only nine of those 
45 payors are small businesses as defined by the U.S. Small Business 
Administration (companies with less than 1,500 employees). MMS further 
estimates that 97 percent of the remaining 755 payors, or 732, would be 
considered small businesses. The nine payors that we consider small 
businesses that we anticipate would be affected substantially by the 
rule make up less than 1.15 percent of all the payors reporting to MMS 
on oil produced from Federal leases and less than 1.25 percent of all 
the small businesses reporting to MMS on oil produced from Federal 
leases.
    Our internal economic analysis of impacts on small businesses shows 
that benefits of pricing simplification and the savings associated with 
transportation allowance changes are likely to outweigh any additional 
administrative costs associated with this rule.

(m) Burden Associated With Compliance, Information Requirements, and 
the Rule in General

    Summary of Comments: Congressional comments stressed the point that 
an overly burdensome rule will discourage further domestic oil 
exploration and development, and that any further burden on industry 
for information should be limited to establishing the value at the 
lease--not downstream of the lease.
    Several groups from industry commented that the rule will increase 
administrative burden on both MMS and the producer. For example, MMS 
will have many requests from industry about value and quality 
determinations whenever companies believe that index pricing overstates 
the real value of their Federal oil production. MMS will not be able to 
timely respond. Thus, industry will have less certainty than before. 
Ignoring the FERC tariff methodology requires a double burden on 
lessees, i.e., having to apply two different sets of rules (FERC's and 
MMS's). The rule will drive producers to revamp business practices--
especially in the mid-stream marketing arena.
    On the other hand, a State commented that the December 1999 
proposal puts too much trust in the industry to supply information. 
Industry should be required to tell MMS when a balancing agreement is 
in place or when oil is subject to a call. This State stressed that MMS 
needs this information up front, not just in an audit. Effectively, the 
burden is on MMS for collecting this information. A watchdog 
organization agrees that it is imperative that industry inform MMS of 
balancing agreements.
    MMS Response: MMS acknowledges that the rule will change the 
current valuation procedures for some integrated producers. However, we 
believe the rule actually results in simpler methodologies that are 
less burdensome than the current regulations.
    We anticipate that the overall impact of the rule will be to 
significantly reduce the time involved in the royalty calculation 
process. Under the rule, in most cases lessees without arm's-length 
sales would report the adjusted spot price applicable to their 
production. For other than production in the RMR, the need to work 
through and apply the current benchmarks for non-arm's-length 
transactions would be eliminated. Many of the variables in royalty 
calculation under the previous rule have been eliminated. This should 
lead to additional savings in audit costs.
    The comments regarding ``value at the lease'' have been addressed 
elsewhere in this preamble. The substance of these comments actually 
relates to downstream sales and what deductions are or are not proper 
in light of the lessee's duty to market.
    The comments regarding having to apply different sets of rules 
between FERC and MMS are, in our view, misplaced. FERC is not charged 
with determining lessees' actual transportation costs for royalty 
purposes. Indeed, many of the pipelines for which lessees may have to 
calculate actual transportation costs are not even within FERC's 
jurisdiction, as explained above.
    The comments regarding the timing of information on balancing 
agreements do not appear to warrant a change from the December 1999 
proposal. Balancing agreements are relevant to the question of whether 
a particular contract reflects the total consideration for disposition 
of the oil. This is typically a matter addressed in the audit context.

(n) MMS's Economic Analysis Fails to Analyze Alternatives as Required 
by Law

    Summary of Comments: A group representing industry believes MMS 
fails to adequately analyze alternatives such as taking royalty in kind 
or tendering. The commenter says that the Administrative Procedure Act 
requires a full economic analysis of all feasible alternatives.
    MMS Response: See response in paragraphs (b), (c), and (d) below in 
the discussion of MMS's responses to the comments on the February 1998 
proposal.

Comments Related to the July 1998 Proposal

    Summary of Comments: Since MMS has significantly changed the rule 
since the February 1998 proposal, a new and revised analysis should be 
performed.
    MMS Response: We revised our analysis using 1998 data. The 
procedures followed in the latest analysis are basically the same as 
those followed with the original analysis.

Comments Related to the February 1998 Proposal: (a) Marketing Costs

    Summary of Comments: Some commenters asserted that the proposed 
valuation methodology will not arrive at the value of oil at the lease. 
They said the adjustments MMS proposes will not account for all costs 
associated with assessing value downstream and away from the lease. 
They argued that for computing value in situations not involving arm's-
length sales, the rule imposes the equivalent of a tax by not allowing 
marketing cost deductions.
    MMS Response: MMS's detailed responses to the obligation of the 
lessee to market production free of cost to the Federal Government are 
discussed in detail in Section III(i).

(b) Alternatives

    Summary of Comments: MMS has not considered the appropriateness of 
non-regulatory alternatives such as taking royalty in kind (RIK) 
instead of in value.
    MMS Response: The MMS has in fact considered several non-regulatory 
alternatives to the rule including RIK. In 1995, MMS undertook an RIK 
pilot project for gas produced from the Gulf OCS and is currently 
operating RIK projects in Wyoming (crude oil in-kind), offshore Texas 
in the zone governed by section 8(g) of the OCSLA (natural gas in 
kind), and in the Gulf of Mexico (natural gas in kind). The objective 
of these pilots is to test the administrative and economic feasibility 
of a variety of methods and conditions of RIK programs. But until MMS 
completes these pilots and analyzes the results, revisions to the 
valuation regulations are needed to assure receipt of market value. 
Also, unless all Federal oil is taken in kind in the future--an 
occurrence we do not foresee--valuation regulations still will be 
needed.
    Furthermore, MMS published a Federal Register notice on September 
22, 1997 (62 FR 49460), requesting comments on alternatives before 
proceeding with the rulemaking. While these are not ``non-regulatory'' 
alternatives, they demonstrate MMS's attempts to involve the public in

[[Page 14079]]

suggesting different valuation methodologies. These alternatives were 
discussed above in Section V of this preamble.
    In short, MMS has considered many alternatives to the rule and 
received numerous comments from interested parties along the way. The 
MMS believes the rule is a practical solution to establishing royalty 
valuation methods that capture the true market value of crude oil 
produced from Federal leases. MMS is considering non-regulatory 
alternatives such as RIK, but is not prepared to take a more 
significant portion of its oil in kind until or unless the results of 
its pilots so dictate. The other valuation alternatives mentioned above 
were deemed to be less desirable and more costly to implement than the 
final rule. For these reasons, MMS determined that they are not 
feasible alternatives or effective means to achieve the same results as 
the rule.

(c) Tendering Programs

    Summary of Comments: Commenters on E.O. 12866 asserted that MMS is 
incorrect in assuming that a tendering program is costly and is only 
valid if a nearby index measure of value does not exist.
    MMS Response: For areas other than the RMR, MMS views index prices 
as the most accurate measure of value for oil not sold at arm's length. 
As mentioned above, the costs of monitoring and establishing a workable 
tendering program, with adequate safeguards to prevent abuse, make it a 
less desirable alternative than index pricing. Because tendering is 
company-specific, information transfer costs and recordkeeping costs 
would be higher than the costs associated with using a transparent, 
reliable indicator of value, such as an index.
    The reason that the final rule includes tendering as a valuation 
benchmark for the RMR is that there is no reliable spot or index price 
specific to that region.

(d) Industry-Proposed Benchmarks

    Summary of Comments: Some commenters stated that MMS rejected an 
industry-proposed benchmark system based on the assumption that it was 
too costly and difficult to administer. It is not clear that the costs 
associated with the new rule are any less severe than the costs 
associated with this proposed benchmark system.
    MMS Response: The Independent Petroleum Association of America 
(IPAA) originally submitted the proposed benchmark system referenced by 
this comment and has since submitted a modified valuation proposal they 
termed ``royalty valuation procedures'' (RVP's). MMS asked for comment 
on IPAA's original proposed benchmark system in a Federal Register 
notice on September 22, 1997 (62 FR 49460) (see above for specifics on 
the proposal and the responses we received). IPAA's modified proposal 
for sales not at arm's length allows the lessee to elect one of the 
following RVP's for a given period of time:
     Outright sales of significant quantities of like-quality 
crude in the field or area, including sales under ``tendering'' 
programs.
     Arm's-length purchases of significant quantities of like-
quality crude in the field or area.
     Netback methodology using an index price or an affiliate's 
resale price minus all actual costs for transportation and value added 
by midstream activities.
     Potential use of outright arm's-length sales by third 
parties in the field or area once the trade press begins routinely to 
publish price data for a given field (this is something that the trade 
press currently does not do; nor are we aware of any trade press plans 
to publish such data).
     Potential use of prices published by MMS based on its RIK 
sales (this idea assumes that a RIK program is feasible and that data 
gathered from it would be applicable and in a usable form).
    State commenters on the February 1998 proposal objected to IPAA's 
menu selection concept.
    As discussed elsewhere in this preamble, the final rule uses index 
prices to value oil not sold at arm's length everywhere except in the 
RMR. While the final rule does not use RVP's for that region, it does 
use a set of benchmarks with some similarities to the RVP's. Also as 
discussed elsewhere in the preamble, MMS believes that except for the 
RMR, spot prices are the best indicators of value.
    In the public workshops, MMS explained in detail the numerous 
problems associated with using area or regional sales and purchases as 
a measure of value. The potential for uncertainty in the terms 
``significant quantities,'' ``like-quality,'' and ``field or area,'' 
leads to significant audit burdens on lessees and MMS. Likewise, the 
first and second RVP's require the lessee to timely obtain access to 
arm's-length contracts in the field or area. The final rule adopts part 
of the third RVP, with deductions limited to the actual costs of 
transportation as prescribed in the rule, as the single valuation 
method for all production not sold at arm's-length, except in the RMR, 
where an index price is used as the third benchmark. However, as 
discussed in Section III(i) of the preamble, the final rule does not 
allow a deduction for midstream marketing activities.
    The last two of IPAA's proposed benchmarks are offered only as 
potential measures, and IPAA admits they cannot be implemented 
currently. MMS is open to studying these proposals in the future if 
they become viable.
    Finally, MMS does not believe that lessees should be permitted to 
select a valuation method simply because it would be to the lessee's 
monetary benefit. Value should be based on uniform standards applicable 
to all lessees similarly situated. In other words, valuation should not 
be based on a menu, but rather on a hierarchy of established standards.

(e) Spot Prices

    Summary of Comments: In their comments on E.O. 12866, commenters 
disagreed with MMS's assertion that spot and spot-related prices drive 
the manner in which crude oil is bought and sold today in the United 
States.
    MMS Response: MMS's detailed response to the adequacy of spot 
prices is contained in Section VI(e).

(f) Cost-benefit Analysis of Alternatives

    Summary of Comments: Commenters stated that MMS fails to meet the 
requirements of E.O. 12866 by not performing a cost-benefit analysis of 
any of the alternatives. They say MMS simply presents a few 
unsubstantiated reasons for not using alternatives, which does not 
allow MMS to choose the most efficient alternative. Further, according 
to the commenters, MMS has not investigated which, if any, alternatives 
arrive at value at the lease.
    MMS Response: The final rule is the culmination of a four-plus year 
rulemaking effort. Throughout this process MMS explored and discussed 
numerous valuation alternatives with States, consultants, interest 
groups, industry groups, and congressional staff. MMS has adopted, at 
least partially, many of the alternatives suggested by commenters. 
However, several suggested alternatives were based on propositions for 
which no data exists for conducting a cost-benefit analysis. 
Furthermore, expert consultant feedback and State support substantiated 
our reasons for not using alternative valuation methods.
    As mentioned previously, MMS is in the process of implementing 
several RIK pilot programs in order to determine the feasibility of 
such an approach. Regardless of the outcome of these pilots, it is 
still necessary to have oil

[[Page 14080]]

valuation regulations in place for the areas where RIK is not feasible.

(g) MMS's Costs Related to Form MMS-4415

    Summary of Comments: Commenters stated that by MMS's own 
calculations, MMS assumes that it will receive approximately 1,750 Form 
MMS-4415 reports annually. The MMS assumes that its team of GS-9 
employees would take only two minutes per form to collect, sort, and 
file the documents. It is likely that this cost is understated.
    MMS Response: MMS has eliminated Form MMS-4415 in the final rule.

(h) Form MMS-4415 Data

    Summary of Comments: Commenters asserted that MMS does not know 
what it is going to do with the collected data from the Form MMS-4415, 
so how can it accurately estimate the time required to analyze and 
publish the data?
    MMS Response: 
    MMS has eliminated Form MMS-4415 in the final rule.

(i) Additional Industry Costs

    Summary of Comments: Commenters on the E.O. 12866 asserted that MMS 
failed to estimate the additional costs that industry would be forced 
to incur under this rule. They include:
     The time required to calculate value under the rule.
     The cost of replacing or upgrading computer systems (the 
commenters say the proposed rule may require some companies to operate 
three different computer systems).
     The increased recordkeeping burden.
     The additional time required to complete other currently-
approved MMS forms.
    MMS Response: Industry stated that new computer systems are needed, 
with the possibility of three separate systems for the three regions of 
the country with separate valuation requirements. However, they did not 
provide any specifics on the costs of system modifications. While some 
payors will have to make some changes to comply with the final rule, as 
is the case with any new rule for a system involving automated reports 
and payments, industry has not shown that these costs will be 
excessive. Further, MMS believes that the majority of payors will 
continue to pay on the gross proceeds received under an arm's-length 
sale. This means that they will not incur any additional computer costs 
in complying with the arm's-length provisions of the new rule. For 
those not paying on gross proceeds, industry has not shown that the 
methods applicable to the three different regions of the country will 
require extensive computer systems overhaul or substantial additional 
staff. Therefore, the final rule includes three geographic regions as 
contained in the February 1998 proposal.
    The new rule does not change statutory document retention 
requirements. There are no additional requirements associated with the 
rule that would result in additional information collection on any of 
MMS's current required forms.

(j) Lessees' Costs of Completing Form MMS-4415

    Summary of Comments: Commenters asserted that MMS was correct in 
including the cost of completing proposed Form MMS-4415, but they said 
that MMS underestimated these costs.
    MMS Response: MMS has eliminated Form MMS-4415 in the final rule.

(k) Sensitivity Analysis

    Summary of Comments: Commenters assert that MMS has not used any 
sensitivity analysis in testing their assumptions.
    MMS Response: The MMS believes that the assumptions made in 
formulating this rule are broad and basic enough that no sensitivity 
analysis is necessary.

(l) Market Distortions and Distributional Impacts

    Summary of Comments: In their comments on E.O. 12866, commenters 
state that MMS has not considered the costs of market distortions or 
distributional impacts that would result from this rule. They say that 
MMS using an average of index prices to arrive at a market price in a 
month is not the same as arriving at a true market price for one 
particular individual. They assert that MMS ignores these 
distributional consequences under the apparent assumption that a single 
average market value concept is an adequate substitute for the range of 
market valuations that are established in the marketplace.
    MMS Response: MMS believes that the index market price--adjusted 
for location, quality, and transportation costs--will approximate 
market values received for individual lease production.

(m) Lessees Will Avoid Filing Requirements

    Summary of Comments: Commenters asserted that the costly filing 
requirements associated with Form MMS-4415 could cause lessees to 
restructure their transactions in such a way as to avoid triggering a 
filing requirement. They claim this is not a free-market outcome.
    MMS Response: MMS has eliminated Form MMS-4415 in the final rule.

(n) FERC-Approved Tariffs

    Summary of Comments: Commenters on the E.O. 12866 state that MMS 
requires the lessee to use ``actual costs'' of transportation rather 
than a FERC-approved tariff. They say this amounts to an additional 
cost or tax that the lessee must pay.
    MMS Response: As explained above in the response to the comments 
received on the December 1999 proposed rule, this does not result in an 
extra cost or tax. All lessees claiming transportation allowances may 
deduct their actual costs of transportation. Those who pay others to 
transport their crude still may deduct a FERC tariff if that is the 
rate they pay at arm's length for the transportation.

(o) Baseline Years

    Summary of Comments: Commenters assert that the choice of baseline 
years from which to calculate the benefits in MMS's impact analysis is 
very important. For example, in 1996, the average price per barrel of 
crude oil from Federal lands was $18.37, whereas recently oil prices 
have been as low as $13 per barrel. At lower prices, the relative 
differences become smaller.
    MMS Response: MMS chose 1996 as a baseline year because that was 
the most recent year for which the normal corrections in royalty 
reporting were complete at the time the February 1998 proposal was 
published, and it represented a year with no market interruptions or 
anomalies. The implication that a lower oil price such as $13 per 
barrel could make MMS's estimates inaccurate, or the relative value 
differences smaller, is misplaced. It is expected that oil prices will 
vary over time, but the effect of a change in prices on the difference 
in royalty value between this rule and the existing rule is unknowable 
without a great deal of additional information. MMS therefore believes 
that there is no basis on which to argue that 1996 is an improper 
baseline year because prices supposedly were too high to be used in 
estimating the impact of the new rule.
    Further, and not as a result of the comment above, we have updated 
the analysis using 1998 royalty data because a significant period of 
time had elapsed since our initial analysis. The results of the revised 
analysis are very similar to those of the study using 1996 data and 
reinforce its validity.

[[Page 14081]]

    As stated earlier, 1996 was selected not because of absolute price 
levels but because it was the most recent year for which reasonably 
complete and corrected data were available. In any event, the relative 
difference in royalty collections at different price levels is 
irrelevant to the central purpose of the rule--ensuring payment of 
royalty on the market value of Federal crude oil.

(p) Assumptions Regarding Benefit Analysis

    Summary of Comments: Commenters on the E.O. 12866 analysis believe 
that MMS's assumption that payors with no refining capacity would 
continue to pay on gross proceeds from arm's-length sales at the lease 
is incorrect. By the same token, producers/ marketers with refinery 
capacity will not always dispose of production at other than arm's 
length, and as a result may be forced to use the index methodology for 
all their oil.
    MMS Response: MMS concedes that there may be cases where integrated 
lessees with refinery capacity sell their oil under true outright 
arm's-length sales. Contrary to the comments, they would be able to use 
their arm's-length proceeds in such cases. However, our audit work and 
the advice of various crude oil consultants indicate that most 
integrated producers are net purchasers of crude oil and either 
exchange their produced oil for oil closer to their refineries or 
directly transport their production to supply their refineries. In 
either case there is not an arm's-length sale of crude oil.
    In contrast, lessees without refinery capacity generally either 
sell their oil at arm's-length or transfer their oil to an affiliate 
who subsequently sells the oil to an unaffiliated refiner. In either 
case, payors without refining capacity generally would value their 
production based on the gross proceeds received under an arm's-length 
contract. This is not a change from how they value production under the 
current rules. For purposes of estimating the revenue impacts of this 
final rule, MMS believes these assumptions are valid.

(q) Proprietary Data

    Summary of Comments: Commenters assert that MMS used proprietary 
data in calculating its estimates, and disclosure was a problem with 
data used in the onshore analysis.
    MMS Response: The Barents Group filed a Freedom of Information Act 
request to obtain all of the data supporting the E.O. 12866 analysis. 
MMS was able to provide all of the data for OCS leases. However, the 
data from onshore leases involves questions of proprietary information 
because of the limited number of payors on those leases, which would 
enable those who review that data to associate a price with an 
individual payor. MMS believes that the only way to accurately estimate 
the revenue impact of the rule is to use actual, company-submitted 
data.

(r) MMS's Spreadsheets

    Summary of Comments: Commenters assert that MMS's spreadsheets are 
not easy to interpret or well documented. In many cases the steps have 
been aggregated into one, and as a result, it is difficult to determine 
how and why MMS proceeded as it did. Further, what MMS describes as its 
methodology is inconsistent with what the spreadsheets present.
    MMS Response: MMS believes that the spreadsheets are adequate and 
the documentation is clear. From the detail of the comments provided it 
appears that the main ideas presented in the analysis were well 
understood.

(s) Analysis for Refiners Versus Non-Refiners

    Summary of Comments: In its comments on the portion of the E.O. 
12866 analysis for offshore California leases, one commenter asserted 
that producers without refinery capacity (i.e., those who normally 
would be expected to pay on arm's-length gross proceeds) now pay 
royalty on a value that is 17.8 percent less than what they would pay 
if value were based on the index price. Further, they say that 
producers with refinery capacity (i.e., those who normally do not have 
arm's-length gross proceeds) now pay royalty on a value that is 10.4 
percent below an index price-based value. They implicitly accuse MMS of 
being contradictory in requiring producers with refinery capacity (who 
do not sell at arm's length) to pay on a higher index-based value, 
while at the same time accepting arm's-length gross proceeds that are 
lower than the value already reported by the producers who do not sell 
at arm's length.
    MMS Response: First, MMS has no basis on which to evaluate the 
accuracy of the commenter's assertions, which amounted to summary 
figures in a table of the commenter's own making. The commenter did not 
submit the underlying documents on which its asserted figures were 
based or explain how it performed its calculations.
    Second, even assuming arguendo that the commenter's calculations 
are accurate, the commenter tries to infer far too much from what may 
have occurred in 1 year in one area. While non-arm's-length reported 
values can be higher than some arm's-length gross proceeds in some 
circumstances, nothing in MMS's experience or the commenter's figures 
indicates that non-arm's-length transfer prices either are or could be 
expected to be consistently higher than arm's-length market prices.
    Indeed, in most instances where oil is first transferred to an 
affiliated marketing entity and then resold at arm's length, the arm's-
length resale price is higher than the inter-affiliate transfer price. 
As explained above, non-arm's-length transfer prices are not reliable 
indicators of what price production will bear in the market. Therefore, 
as discussed in detail throughout this preamble, MMS must look to other 
reliable indicators of value such as index prices to establish value in 
those cases.

(t) Transportation Adjustments in the Analysis

    Summary of Comments: Commenters assert that MMS states that for its 
comparison, it used prices reported on the Form MMS-2014 less any 
reported transportation allowances. Yet they say that when the 
spreadsheets are examined, it appears that transportation adjustments 
are not included.
    MMS Response: MMS compared the price reported on Form MMS-2014 to 
the location, quality- (if applicable) and gravity-adjusted spot price 
at the first onshore delivery point, assuming that all payors reported 
a royalty due line (Transaction Code 01) representing the value at the 
onshore delivery point and a separate transportation allowance line 
(Transaction Code 11) representing the costs of transporting the oil to 
shore. That is, MMS compared (1) the onshore spot price, adjusted for 
the actual reported gravity at the least or a weighted average gravity 
for a unit, to (2) the price reported by the payor for the royalty due 
line without deducting any reported transportation allowance for that 
line. This allows an ``apples to apples'' comparison rather than 
comparing values at two different points.
    If a payor incorrectly netted its transportation allowance from the 
reported royalty due instead of reporting the transportation allowance 
on a separate line, or if the payor sold its oil at the lease and 
incurred no transportation to move the oil to shore, MMS acknowledges 
that the revenue impact estimate for offshore California and the Gulf 
of Mexico may be overstated to that extent. However, if a payor does 
not report a separate transportation allowance on Form MMS-2014, MMS 
has no way of knowing the costs of transporting the

[[Page 14082]]

production to shore to equate the reported price to the onshore spot 
price. Absent any other reasonable alternatives, MMS chose this 
methodology recognizing that the revenue impact could be slightly 
overstated, assuming at the same time that very few payors reported 
incorrectly. MMS correctly used the reported value on the Form MMS-2014 
without including the reported adjustments for transportation.

(u) Gravity Adjustments

    Summary of Comments: In their comments on the E.O. 12866 analysis, 
commenters stated that it is not clear why MMS does not use actual 
gravities in its offshore California analysis, but rather uses a 
weighted average gravity value within a unit and applies that value to 
all the leases in the unit. Commenters also believe that MMS does not 
account for gravity adjustments for oil in the range of 34 deg. to 
40 deg. API and makes mistakes in calculating the gravity adjustments 
in several months.
    MMS Response: MMS used the weighted average gravity for an entire 
unit because there were many cases where gravity was missing or 
reported incorrectly by royalty payors. In those cases, MMS believes 
that using a weighted average gravity is appropriate. However, the 
revised analysis that accompanied the December 1999 proposed rule used 
actual reported lease gravity. After an examination of the data, it 
appeared the reported gravity values were complete and accurate in 
1998. Using a weighted average was not necessary.
    MMS adjusted California crude oil production values using Chevron's 
posted price adjustment scale in effect for the month of production. 
The scale does indeed include adjustment values for the range of 
34 deg. to 40 deg.; however, none of the weighted average gravities 
fell into this range. As a result, it was not necessary to include this 
adjustment in the calculations.
    Additionally, there were months where the adjustment scale changed 
mid-month. As a result, some adjustments were based on a value that 
approximated the value in effect for the full month. For example, if 
the adjustment scale in effect for the first half of the month was $.15 
per degree API gravity and for the last half of the month it changed to 
$.20 per degree, MMS used a value of $.17 per degree to approximate the 
value of the deduction for the entire month. So, although in such cases 
the commenters may have believed a mistake occurred, it did not.

(v) Use of Pipeline Tariffs in the Analysis

    Summary of Comments: MMS uses pipeline tariffs in its estimates, 
yet the rule does not allow tariffs for payors with affiliated 
pipelines.
    MMS Response: Absent other publicly-available information regarding 
transportation costs, MMS used tariffs in the analysis as a general 
proxy for location differentials between (1) the lease and (2) market 
centers for which spot prices are published. MMS has found that tariff 
rates generally exceed the actual costs of transportation, so using 
them in the analysis, if anything, would understate the revenue impact 
of the final rule.

(w) Analysis for New Mexico

    Summary of Comments: Commenters assert that for MMS's onshore New 
Mexico estimates, a charge of $.25 per barrel is assessed for movement 
from aggregation points to Midland, Texas. The basis for this charge is 
never substantiated.
    MMS Response: MMS based the $0.25 per barrel differential between 
aggregation points in New Mexico and the market center at Midland, 
Texas, on information it obtained from an industry contact who trades 
oil in that area.

(x) Differential Timing

    Summary of Comments: Commenters said that lessees who are required 
to use differentials that are set once a year by MMS may overvalue or 
undervalue production because of the many changes in the market and oil 
quality over a year's time.
    MMS Response: MMS has eliminated Form MMS-4415 in the final rule.

(y) Use of Unaudited Data

    Summary of Comments: We received comments that MMS uses unaudited 
data for 1996, yet normal audit collections result in an average 3% 
revenue gain. This expected audit collection, the commenters allege, 
equals 71 percent of the MMS estimate of $66 million.
    MMS Response: We do not know how much additional money will be 
collected through audit for any given period until audits are completed 
and money is collected. Nor do we know in advance exactly what the 
difference in royalty liability between this rule and the existing rule 
will be. Of necessity, our estimate of the revenue effects of this rule 
is just that--an estimate. But the objective in developing these 
regulations is to obtain a better measure of the real value of oil 
produced from Federal leases. We acknowledge that in many cases--arm's-
length sales being a prominent example--royalty value will not change 
under this rule. In other cases, it will.

(z) Location Differentials, Rocky Mountain Region

    Summary of Comments: Commenters asked if, as reported in its 
analysis, MMS could not calculate a differential for the RMR between 
Cushing, Oklahoma, and the fields of each State, how is industry 
expected to report this differential?
    MMS Response: When MMS did its analysis, it did not have the 
necessary contracts in hand to calculate such differentials. 
Regardless, MMS believes that lessees that will be subject to index 
pricing generally will have sufficient information to accurately 
determine location/quality differentials, with relatively rare 
exceptions. Only lessees who sell their oil to affiliates who then 
either move the oil to market for sale at arm's-length or move the oil 
to a refinery are required (or can elect) to use index pricing. In 
those cases, MMS believes that lessees will either physically transport 
or exchange their oil to either a market center or a refinery and will 
therefore have the information necessary to determine location/quality 
and transportation adjustments from the index price. As a result, MMS 
has eliminated Form MMS-4415 in the final rule.

(aa) Quality Adjustments, Rocky Mountain Region

    Summary of Comments: The MMS analysis for the RMR does not account 
for crude oil quality. This may invalidate the results of the analysis.
    MMS Response: For the analysis that accompanied the December 1999 
proposed rule, we had more complete information; we were able to 
isolate production to specific areas within some States. This better 
accounts for quality differences that may be found by commingling all 
production within a State.

(ab) Federal Administrative Savings

    Summary of Comments: Commenters asked, if the rule will result in 
administrative savings to the Federal government, why are these savings 
not quantified?
    MMS Response: The MMS is confident that administrative costs will 
be reduced. In our latest analysis, we make reference to administrative 
savings for both industry and the government. However, specifically 
quantifying these benefits is difficult. Audit costs are expected to 
fall as higher, correctly-reported royalties are realized initially 
when royalty is due.

[[Page 14083]]

MMS verification still will be needed, but we expect that the process 
will be more efficient.

(ac) MMS's Onshore California Analysis

    Summary of Comments: Commenters stated that when MMS analyzed the 
onshore California impact, they only analyzed the Midway-Sunset field 
because the majority of Federal onshore oil production in California 
comes from this field. According to the commenters, MMS does not say 
whether the results are for the Midway-Sunset field only or somehow 
extrapolated to all fields onshore.
    MMS Response: This analysis is a refinement of our earlier analysis 
(that used 1996 data) and contains several significant differences. The 
earlier analysis treated all onshore California Federal oil production 
as if it were produced in the San Joaquin Valley (from the Midway 
Sunset field). The current analysis used 1998 data and matches 
production to the area produced.
    Following is a summary of MMS's revised economic analysis, which 
provides additional details for onshore California as well as the rest 
of the country.

Economic Analysis--Royalty Impact on Federal Lessees

    Note:  The complete analysis is not reproduced here, only the 
sections that generated the most comment. The entire analysis is 
available upon request.

    We are revising our original estimate of approximately $66 million 
in increased royalty revenue that accompanied previous proposals of 
this rule. We used the same general approach to estimate the impact of 
the December 1999 proposal, except with updated 1998 data.
    To estimate the impact and additional royalties collected under the 
December 1999 proposal, we divided the analysis of quantifiable 
benefits into three sections, consistent with the three geographic 
divisions of the proposal:
     California (both onshore and offshore)
     Offshore Gulf of Mexico (this also includes onshore New 
Mexico, Texas, and Louisiana)
     Rocky Mountain Region
    For each of the geographic areas, we compared the royalty paid in 
1998 for oil and condensate either directly to MMS or through the small 
refiner royalty-in-kind program to what would have been required under 
the valuation requirements of the December 1999 proposal. We examined 
each month of 1998 separately. We chose the year 1998 because it:
     Is the last complete year in which all months of data were 
available.
     Includes wide variations in prices over the 12-month span.
     Reflects data incorporating most of the edits and 
corrections performed by the exception processing modules in MMS's 
Auditing and Financial System/Production and Accounting and Auditing 
System.
    We focused on the onshore leases in California, Colorado, Montana, 
North Dakota, New Mexico, Utah, and Wyoming because together they 
account for about 95 percent of total onshore Federal oil production. 
For offshore California and the Gulf of Mexico, we used 100 percent of 
the oil volumes and values for this analysis.
    When examining the payments received from Federal onshore and 
offshore leases, we grouped all the royalty reporters into five 
separate categories:
    1. Major integrated producers with refinery capacity;
    2. Large, independent producers/marketers with refinery capacity;
    3. Large, independent producers/marketers with no refinery 
capacity;
    4. Small, independent producers with refinery capacity (this 
category is different than small businesses as defined by the Small 
Business Administration); and
    5. Small, independent producers with no refinery capacity.

Offshore California

    Under the December 1999 proposal, the value of production sold 
under an arm's-length contract would be the gross proceeds received 
under that contract. Oil not sold at arm's length would be valued on 
either (1) the average of the daily mean Alaska North Slope (ANS) spot 
prices published in an MMS-approved publication during the calendar 
month preceding the production month, or (2) the gross proceeds 
received by the affiliate under an arm's-length contract. The lessee 
would have to adjust the value for applicable location and quality 
differentials, and may adjust it for transportation costs. We believe 
that all large, independent producers/marketers with no refinery 
capacity (Category 3) and small independent producers (Category 5) 
would value crude on the basis of arm's-length gross proceeds. 
Therefore, we did not include them in the analysis. We examined the 
other three categories of royalty payors using the following procedure:
     We grouped all production by unit (i.e. Beta, Santa Ynez, 
etc.).
     We determined an average gravity for each lease in the 
unit.
     We made gravity adjustments to equate the unit oil to the 
26.5 deg. API ANS oil, using Chevron's California posted price gravity 
adjustment scale in effect during the month of production.
     We subtracted a location differential from the ANS value 
in Los Angeles to arrive at a value at the first onshore delivery 
point, which coincides with the value reported on Form MMS-2014. We 
used the following per-barrel location differentials relying on several 
sources, but primarily tariff schedules:

Beta: $0.10
Pitas Point: $0.50
Point Hueneme: $0.50
Point Pedernales: $0.50
Rocky Point: $2.20
Santa Clara: $0.50
Santa Ynez: $2.20

     We subtracted sulfur penalties from the ANS price where 
appropriate. These penalties were based on All-American Pipeline sulfur 
bank adjustments and consultant reports. We used a value of $0.56 for 
each percent sulfur above the benchmark ANS sulfur content of 1.1 
percent. The per-barrel sulfur adjustments are:

Beta: $1.46
Point Pedernales: $1.62
Rocky Point: $1.79
Santa Ynez: $1.74
Santa Clara $1.46

     We then compared, for each month in 1998, (1) the location 
and quality-adjusted ANS price to (2) the actual price reported by each 
royalty reporter on Form MMS-2014. We then multiplied this incremental 
value by the royalty quantities reported on Form MMS-2014 to arrive at 
an overall net gain or loss associated with the rulemaking.
    Our earlier analysis (using 1996 data) involved several factual 
differences. For example, the unadjusted average ANS price for 1996 was 
$20.45, versus $12.55 in 1998. (We wouldn't have expected different 
relative prices, in and of themselves, to cause a major difference in 
the results of the revised study, and that observation is borne out 
here.) Also, oil production from Federal Offshore California leases 
declined from 67,804,200 to 40,636,231 barrels--a drop of approximately 
40 percent from 1996 to 1998. Further, the effective royalty rate for 
offshore California crude oil dropped by 1.6 percent (largely due to 
MMS-approved royalty rate reductions).
    We updated the sulfur content related to various offshore fields 
and added a sulfur adjustment for the Santa Clara Unit. We made further 
revisions to the transportation rates from the onshore delivery points 
to the refining centers

[[Page 14084]]

for offshore California production. While we recognize that not all 
payors will pay the same transportation rates, we used rates that we 
believe capture a reasonable representation on average of the rates 
paid by lessees.
    Estimated 1998 revenue gains under this final rule are:

 Category (1)...................................      $4,363,837
 Category (2)...................................         241,247
 Category (4)...................................         126,429
                                                         ---------------
  Total.................................................      $4,731,513
 

    In 1998, California received about 4 percent of the Federal oil 
royalties from the California OCS--$1.96 million of $48.5 million 
total--under OCSLA section 8(g), 43 U.S.C. 1337(g), which provides for 
coastal States to share in royalties from Federal leases lying wholly 
or partially within three miles from the State's seaward boundary. 
Applying the same 4 percent to the above estimate equates to $189,261 
in additional revenue for the State of California.

Onshore California

    To determine the impact of the December 1999 proposal on onshore 
payors in California, we aggregated the production for Categories (1) 
and (4). This comprised over 80 percent of the Federal onshore 
California production. We assumed that Category (5) payors would pay 
royalties based on their gross proceeds. There was no Federal onshore 
California production for Categories (2) and (3) in 1998.
    We arrived at a monthly price at the lease by taking the ANS spot 
price adjusted for:
    1. Gravity (using Chevron's posted price gravity adjustment scales 
in effect during production year 1998 to reflect differences in ANS and 
onshore field reported gravity from Form MMS-2014).
    2. Transportation charges:

San Joaquin Valley to Los Angeles--$1.00 per barrel
North San Joaquin Valley to Bay Area--$0.50 per barrel
Ventura Basin to Los Angeles--$.50 per barrel
Salinas Basin to Santa Maria--$1.50 per barrel

    These four production areas represent over 80 percent of all 
Federal onshore California production.
    We then compared, for each month in 1998, (1) the location and 
quality-adjusted ANS price to (2) the actual price reported by each 
category 1 and 4 royalty reporter on Form MMS-2014. We then multiplied 
this incremental value by the royalty quantities reported on Form MMS-
2014 to arrive at an overall net gain or loss associated with the 
rulemaking.
    As noted above, this analysis is a refinement of our earlier 
analysis (but using 1996 data) and contains some significant 
differences. The earlier analysis treated all onshore California 
Federal oil production as if it were produced from the Midway Sunset 
field. The current analysis used 1998 data and matches production to 
the area produced. Also, transportation rates are more reflective of 
lease locations than in the previous analysis. The rate for Salinas 
Basin crude assumes that all Federal oil produced there is transported 
by truck.
    Oil production increased from onshore Federal California leases by 
about 8 percent from 1996 to 1998 although the effective royalty rate 
declined by 2.5 percent (largely due to stripper well royalty rate 
reductions). Again, while we recognize that not all payors will pay the 
same transportation rates, we used rates that we believe capture a 
reasonable representation, on average, of the rates paid by lessees.
    Using the procedures in the December 1999 proposal, we estimate a 
1998 revenue impact of:

 Category (1)...................................      $1,638,053
 Category (2)...................................               0
 Category (4)...................................           9,277
                                                         ---------------
  Total.................................................      1,647,330
 
This revenue is shared 50% with the State of California.

Offshore Gulf of Mexico

    The December 1999 proposal established the value of oil not sold at 
arm's length as either:
    (1) The average of the daily mean spot price published in an MMS-
approved publication--
    (a) For the market center nearest the lease for crude oil similar 
in quality to the lessee's production, and
    (b) For deliveries during the production month, or
    (2) the gross proceeds received by the affiliate under an arm's-
length contract.
    The lessee would have to adjust the value for applicable location 
and quality differentials, and may adjust it for transportation costs.
    There were three different spot prices published for Gulf of Mexico 
oil in 1998: Eugene Island (30 deg. API, 1.61 percent sulfur), Heavy 
Louisiana Sweet (32 deg. API, .3 percent sulfur), and Light Louisiana 
Sweet (37-38 deg. API, .3 percent sulfur).
    We believe that all large, independent producers/ marketers with no 
refinery capacity (Category 3) and small independent producers with no 
refinery capacity (Category 5) would value crude oil on the basis of 
arm's-length gross proceeds. Therefore, they were not included in the 
analysis. We examined the other three categories using the following 
procedure:
     We identified each individual area and block for each 
Federal offshore Gulf of Mexico lease.
     We assigned an oil type that most closely represented the 
oil and condensate specific to each area and block.
     The assigned oil type typically translated directly to the 
same spot price (e.g., Eugene Island Oil translates directly to the 
Eugene Island spot price), but in some limited cases, there was no spot 
price published for the identified oil type (e.g. Mars grade crude). In 
these cases, we used the spot oil with the characteristics that most 
closely matched the identified oil (e.g., we used the Eugene Island 
spot price for Mars oil).
     We calculated the average gravities by payor reported for 
each lease.
     We made gravity adjustments to the spot price using 
Equilon Oil Company's (Shell Oil Company in January 1998) offshore oil 
posted price adjustment scale in effect at the time of production.
     We deducted location differentials from the spot price for 
the actual movement of the oil from its first onshore location to the 
spot market. This value was based on FERC tariffs in effect for 
transport from major onshore gathering points to the spot market 
centers.
     We then compared the location- and quality-adjusted spot 
price to the value reported on Form MMS-2014 for each month in 1998. We 
then multiplied any difference by the royalty quantity for each lease 
and aggregated the differences.
    Under the December 1999 proposal, we estimate a 1998 revenue gain 
of:

 Category (1)...................................     $52,450,062
 Category (2):..................................       4,658,893
 Category (4):..................................       2,076,900
                                                         ---------------
  Total.................................................      59,185,855
 

    In 1998, Texas and Louisiana received about 0.5 percent of the 
Federal oil royalties from the Gulf OCS--$4.9 million of $860 million 
total--under OCSLA section 8(g). Applying the same 0.5 percent to the 
above estimate equates to $295,929 in additional revenue for Texas and 
Louisiana.

Onshore New Mexico

    For New Mexico, we split production into two subgroups: the Permian 
Basin and San Juan Basin. Since the production from New Mexico is 
roughly 60 percent sweet and 40 percent sour, we used the same 60/40 
proportion to calculate a weighted average of the spot prices for West 
Texas Intermediate (at

[[Page 14085]]

Midland, Texas) and West Texas Sour. We then arrived at a monthly price 
at the lease by taking this weighted average spot value at Midland, 
Texas, less a charge for transportation specific to the production 
basin ($0.36 for Permian Basin Crude and $0.59 for San Juan Basin), and 
a gravity deduction based on 1998 Form MMS-2014 data. The 
transportation deductions came from the actual per-barrel tariff rates 
charged by pipelines in the area.
    We compared (1) the monthly spot price at the lease to (2) the 
Category 1, 2, and 4 unit prices less any transportation allowances 
reported on Form MMS-2014. We multiplied this per-barrel incremental 
difference by the reported royalty quantity to compute the theoretical 
royalty gain or loss. We assumed there would be no revenue impact for 
the large independent producers/marketers without refinery capacity 
(Category 3) or the small independent producers without refinery 
capacity (Category 5) because they would pay on gross proceeds accruing 
from arm's-length sales.
    Estimated 1998 revenue gains under the December 1999 proposal for 
onshore New Mexico are:

 Category (1)...................................        $343,354
 Category (2)...................................         185,883
 Category (4)...................................         240,283
                                                         ---------------
  Total.................................................         769,520
 

This additional revenue would be shared 50% with New Mexico.

Rocky Mountain Region

    We determined that calculating royalty value differences by State 
under the benchmark criteria for the RMR would not be meaningful due to 
lack of information. It is difficult to estimate what unit value a 
tendering program would have yielded, and we could not reasonably 
estimate how much production would be offered for sale. It is also 
difficult to determine the volume-weighted average price of a lessee's 
arm's-length sales and purchases from a field/area or whether that 
volume met the 50-percent threshold since we could not determine what 
sales or purchases were at arm's length. Also, we could not determine a 
location/quality differential from Cushing, Oklahoma, to the relevant 
fields/areas in each State due to lack of such transaction information.
    In order to arrive at a fair market price that approximated arm's-
length sales (i.e., attempting to mirror the valuation criteria), we 
utilized the monthly weighted average unit value per barrel for the 
large and small independent producers/marketers with no refining 
capacity (Categories 3 and 5). Those prices usually were higher than 
any of the three refiners' categories (1, 2, and 4) unit prices. We 
decided that this calculated arm's-length price would be a 
conservative, yet reasonable proxy for unit value payable under this 
final rule.
    For Montana, North Dakota, and Utah we were unable to split the oil 
volumes into sweet and sour crudes (or Yellow and Black Wax for Utah), 
so we assumed that the lessees grouped into the five categories 
produced proportional volumes of the various crude types. Since we 
utilized unit prices that had already been adjusted for quality, we did 
not make any further quality adjustments.
    For Wyoming, we split production into three distinct areas for 
review: Big Horn Basin, Green River Basin, and Powder River Basin 
(including the Wind River, Hanna, Laramie, and Denver-Julesberg 
Basins). The Powder River Basin contains roughly proportionate volumes 
of sweet and sour production. For Colorado, we split the analysis into 
the two dominant areas of production: Rangely and Denver-Julesburg.
    Once we grouped the production into areas, we took the monthly 
weighted average unit price for the large and small independent 
producers/marketers with no refining capacity (Categories 3 and 5) and 
compared that price to unit prices of leases in the refiner categories 
(1, 2, and 4) as reported on Form MMS-2014. We multiplied the price 
difference per barrel by the royalty quantity to compute the royalty 
gains or losses. We assumed there would be no revenue impact for the 
large independent producers/marketers (Category 3) or the small 
independent producers (Category 5), because they would continue to pay 
on gross proceeds.
    Estimated 1998 revenue gains under this final rule for the RMR (see 
Appendix A for actual State-by-State breakdown) are:

 Category (1)...................................        $880,417
 Category (2)...................................         196,127
 Category (4)...................................         384,316
                                                         ---------------
    Total...............................................      $1,460,860
 

This amount would be shared 50% with the States.
    Overall Increase in Revenue:
    In summary, based on the 1998 comparison, we estimate the following 
additional revenues:

 Category 1, major integrated producers with         $59,675,723
 refiner capacity.......................................
 Category 2, large, independent producers with         5,282,150
 refiner capacity.......................................
 Category 4, small, independent producers with         2,837,205
 refiner capacity.......................................
                                                         ---------------
   Grand Total..................................      67,795,078
 

This estimate does not include estimated benefits to industry which 
bring the net increase in cost to industry to approximately $67.3 
million.

Executive Order 12988

    In accordance with Executive Order 12988, the Office of the 
Solicitor has determined that this rule will not unduly burden the 
judicial system and meets the civil justice reform requirements of 
sections 3(a) and 3(b)(2) of this Executive Order.

Paperwork Reduction Act

    The collections of information associated with this final rule were 
approved by OMB on February 22, 2000 (OMB Control Number 1010-0136, 
expiration date February 28, 2003). We estimate that there will be 45 
respondents who will submit 85 responses. The frequency of response 
varies by rulemaking section. We estimate that the total annual burden 
is 17,711.5 hours, and, using a cost of $50 per hour, the total annual 
cost is $885,575.
    For estimating the burden on industry, we divided the information 
collection requirements of the rule into the five areas which are 
summarized below in table format with specific supporting details 
following each table.
    a. Proper valuation of oil not sold at arm's-length.

[[Page 14086]]



--------------------------------------------------------------------------------------------------------------------------------------------------------
                                             Reporting and
        30 CFR 206  subpart C                recordkeeping                 Frequency              Number of        Burden  (in hours)     Annual burden
                                             requirements                                        respondents                                  hours
--------------------------------------------------------------------------------------------------------------------------------------------------------
206.103..............................  Calculate value of oil    Annually....................              45   Category 1-222.5.......         4,231.5
                                        not sold at arm's-                                                      Category 2-116.........
                                        length..                                                                Category 3-31.25.......
--------------------------------------------------------------------------------------------------------------------------------------------------------

    For the reporting requirements associated with Section 206.103, we 
estimate that there are 45 respondents (lessees of Federal oil leases) 
that will be required to perform certain calculations and adjustments. 
We estimate that the total initial burden for all lessees without 
arm's-length transactions is 4,231.5 hours at a cost of $211,575.
    We anticipate that companies would have to sort through their 
exchange agreement contracts before the relevant ones can be compiled 
and the required information extracted and used in their royalty 
computations. We believe the final rule would impact approximately 45 
Federal oil lessees that would be required to use index pricing. For 
purposes of estimating the burden impact of this rule, we have 
categorized these lessees into three categories:

    Category 1 lessees are companies with over 30 million barrels of 
annual production (this included 13 Federal lessees from our impact 
analysis).
    Category 2 lessees are companies with annual domestic production 
between 10 and 30 million barrels (this included four Federal 
lessees from our impact analysis).
    Category 3 lessees are companies with less than 10 million 
barrels of annual domestic production (this included 28 Federal 
lessees from our impact analysis).

    We estimate that Category 1 lessees each would have approximately 
1,000 exchange agreement contracts to review annually to identify the 
relevant contracts needed for proper valuation under this final rule. 
Of those contracts, we estimate that each company would have to use 250 
exchange agreements in its royalty reporting. We estimate that the 
reporting burden for a Category 1 company is 222.5 hours, including 80 
hours to aggregate the exchange agreement contracts to a central 
location, 80 hours to sort and identify the relevant ones, and 62.5 
additional hours to extract the relevant information and apply it in 
reporting royalties. We estimate the total reporting burden for the 13 
Category 1 companies would be 2,892.5 hours (222.5 hours  x  13 
companies), including recordkeeping; using a per-hour cost of $50, the 
total cost would be $144,625.
    We estimate that Category 2 lessees each would have approximately 
250 exchange agreement contracts to review annually to identify the 
relevant contracts needed for valuation under this rule. Of those 
contracts, we estimate that each Category 2 company would have to use 
63 exchange agreements. We estimate that the reporting burden for a 
Category 2 company would be 116 hours, including 60 hours to aggregate 
the exchange agreement contracts to a central location, 40 hours to 
sort them, and 16 additional hours to extract the relevant information 
and apply it in reporting royalties. For the four Category 2 companies, 
we estimate the total burden would be 464 hours (116 hours  x  4 
companies), including recordkeeping; using a per-hour cost of $50, the 
total cost would be $23,200.
    We estimate that Category 3 lessees each would have approximately 
50 exchange agreements to review annually to identify the relevant 
contracts needed for valuation under this rule. Of those contracts, we 
estimate that each Category 3 company would have to use 13 exchange 
agreements. We estimate that the burden for each Category 3 company 
would be 31.25 hours, including 20 hours to aggregate the exchange 
agreement contracts to a central location, eight hours to sort them, 
and 3.25 additional hours to extract the relevant information and apply 
it in reporting royalties. For the 28 Category 3 companies, we estimate 
that the burden would be 875 hours (31.25 hours  x  28 companies), 
including recordkeeping; using a per-hour cost of $50, the total cost 
would be $43,750.
    We expect the annual burden to decline somewhat as industry becomes 
more familiar with the proposed valuation requirements.
    b. Approval of benchmarks in the Rocky Mountain Region.

--------------------------------------------------------------------------------------------------------------------------------------------------------
                                         Reporting and  recordkeeping                                        Number of      Burden  (in    Annual burden
         30 CFR 206 subpart C                    requirements                       Frequency                responses        hours)           hours
--------------------------------------------------------------------------------------------------------------------------------------------------------
206.103(b)(1).........................  Obtain MMS approval for         1-2 annually....................               2             400             800
                                         tendering program.
206.103(b)(4).........................  Obtain MMS approval for         1-2 annually....................               2             400             800
                                         alternative valuation
                                         methodology.
--------------------------------------------------------------------------------------------------------------------------------------------------------

    For the reporting requirements related to MMS approval of using the 
benchmarks, we estimate that there will be two responses for each of 
the two reporting requirements. On occasion, they will be required to 
submit requests to us in writing.
    We anticipate that a lessee will undertake the following four steps 
in the formulation of specifics surrounding a tendering program or 
alternate valuation strategy: (1) formulation of valuation methodology: 
100 hours, (2) economic evaluation of methodology: 100 hours, (3) legal 
review of methodology: 150 hours, and (4) presentation to MMS: 50 
hours, for a total of 400 hours.
    We anticipate four requests a year for an annual burden of 1,600 
hours, including recordkeeping. Based on a per-hour cost of $50, we 
estimate that the cost to industry is $80,000.
    c. Requirements related to requested valuation determinations and 
approval of location/quality adjustments from MMS.

--------------------------------------------------------------------------------------------------------------------------------------------------------
                                           Reporting and recordkeeping                                       Number of      Burden  (in    Annual burden
          30 CFR 206 subpart C                    requirements                      Frequency                responses        hours)           hours
--------------------------------------------------------------------------------------------------------------------------------------------------------
206.107(a)(1)-(6)......................  Request a value determination   1-2 monthly....................               8             330           2,640
                                          from MMS.
206.112(b).............................  Request MMS approval for        1-2 monthly....................               8             330           2,640
                                          location/quality adjustment
                                          under non-arm's-length
                                          exchange agreements.

[[Page 14087]]

 
206.112(f).............................  Request MMS for location/       1-2 monthly....................               8             330           2,640
                                          quality adjustment when
                                          information is not available.
--------------------------------------------------------------------------------------------------------------------------------------------------------

    We anticipate that companies may request value determinations on 
how royalty statutes, regulations, administrative decisions, and 
policies apply to a specific set of facts. Their requests would have 
to: (1) Be in writing; (2) identify specifically all leases involved, 
the record title or operating rights owners of those leases, and the 
designees for those leases; (3) completely explain all relevant facts. 
They must inform MMS of any changes to relevant facts that occur before 
MMS responds to their request; (4) include copies of all relevant 
documents; (5) provide their analysis of the issue(s), including 
citations to all relevant precedents (including adverse precedents); 
and (6) suggest their proposed valuation method.
    For the above written requests, we estimate that there will be 
eight responses annually for each of the reporting requirements. We 
estimate the annual burden for each of these is 2,640 hours, including 
recordkeeping. Based on a per-hour cost of $50, we estimate the cost to 
industry is $132,000. The total burden is estimated at 7,920 hours and 
$396,000.
    d. Requirements related to special requests due to unique 
circumstances.

--------------------------------------------------------------------------------------------------------------------------------------------------------
                                           Reporting and recordkeeping                                       Number of      Burden  (in    Annual burden
          30 CFR 206 subpart C                     requirements                      Frequency               responses        hours)           hours
--------------------------------------------------------------------------------------------------------------------------------------------------------
206.103(e)(1) and (2)(i)-(iv)..........  Obtain MMS approval to use       1-2 annually..................               2             330             660
                                          value determined at refinery.
206.110(b)(2)..........................  Propose transportation cost      1-2 annually..................               2             330             660
                                          allocation method to MMS when
                                          transporting more than one
                                          liquid product under an arm's-
                                          length contract.
206.110(c)(1) and (3)..................  Propose transportation cost      1-2 annually..................               2             330             660
                                          allocation method to MMS when
                                          transporting gaseous and
                                          liquid products under an arm's-
                                          length contract.
206.111(g) and (g)(1)..................  Elect actual transportation      1-2 annually..................               2             330             660
                                          cost method and depreciation
                                          method for non-arm's-length
                                          transportation allowances.
206.111(i)(2)..........................  Propose transportation cost      1-2 annually..................               2             330             660
                                          allocation method to MMS when
                                          transporting more than one
                                          liquid product under a non-
                                          arm's-length contract.
206.111(j)(1) and (3)..................  Propose transportation cost      1-2 annually..................               2             330             660
                                          allocation method to MMS when
                                          transporting gaseous and
                                          liquid product under a non-
                                          arm's-length contract..
--------------------------------------------------------------------------------------------------------------------------------------------------------

    There are several provisions in the rule that allow the lessee to 
propose some special consideration because the existing provisions of 
the rule may not precisely fit their situation. Like the written 
requests outlined above, their requests would have to: (1) Be in 
writing; (2) identify specifically all leases involved, the record 
title or operating rights owners of those leases, and the designees for 
those leases; (3) completely explain all relevant facts. They must 
inform MMS of any changes to relevant facts that occur before MMS 
responds to their request; (4) include copies of all relevant 
documents; (5) provide their analysis of the issue(s), including 
citations to all relevant precedents (including adverse precedents); 
and (6) suggest their proposed valuation method.
    For the reporting requirements related to special requests because 
of unique circumstances, we estimate that there will be two responses 
for each of the six situations above. We estimate the annual burden for 
each of these is 660 hours, including recordkeeping. Based on a per-
hour cost of $50, we estimate the cost to industry is $33,000. The 
total burden is estimated to be 3,960 hours and $198,000.

e. Currently-approved information collections.

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


[[Page 14088]]

National Environmental Policy Act of 1969

    We have determined that this rulemaking is not a major Federal 
action significantly affecting the quality of the human environment, 
and a detailed statement under section 102(2)(C) of the National 
Environmental Policy Act of 1969 (42 U.S.C. Sec. 4332(2)(C)) is not 
required.

List of Subjects 30 CFR Part 206

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

    Dated: March 6, 2000.
Sylvia V. Baca,
Acting Assistant Secretary for Land and Minerals Management.


    For the reasons given in the preamble, 30 CFR part 206 is amended 
as set forth below:

Part 206--Product Valuation

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

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

    2. Subpart C--Federal Oil is revised to read as follows:
Subpart C--Federal Oil
Sec.
206.100   What is the purpose of this subpart?
206.101   What definitions apply to this subpart?
206.102   How do I calculate royalty value for oil that I or my 
affiliate sell(s) under an arm's-length contract?
206.103   How do I value oil that is not sold under an arm's-length 
contract?
206.104   What index price publications are acceptable to MMS?
206.105   What records must I keep to support my calculations of 
value under this subpart?
206.106   What are my responsibilities to place production into 
marketable condition and to market production?
206.107   How do I request a value determination?
206.108   Does MMS protect information I provide?
206.109   When may I take a transportation allowance in determining 
value?
206.110   How do I determine a transportation allowance under an 
arm's-length transportation contract?
206.111   How do I determine a transportation allowance under a non-
arm's-length transportation arrangement?
206.112   What adjustments and transportation allowances apply when 
I value oil using index pricing?
206.113   How will MMS identify market centers?
206.114   What are my reporting requirements under an arm's-length 
transportation contract?
206.115   What are my reporting requirements under a non-arm's-
length transportation arrangement?
206.116   What interest and assessments apply if I improperly report 
a transportation allowance?
206.117   What reporting adjustments must I make for transportation 
allowances?
206.118   Are actual or theoretical losses permitted as part of a 
transportation allowance?
206.119   How are the royalty quantity and quality determined?
206.120   How are operating allowances determined?
206.121   Is there any grace period for reporting and paying 
royalties after this subpart becomes effective?
Sec. 206.100   What is the purpose of this subpart?

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


Sec. 206.101  What definitions apply to this subpart?

    The following definitions apply to this subpart:
    Affiliate means a person who controls, is controlled by, or is 
under common control with another person. For purposes of this subpart:
    (1) Ownership or common ownership of more than 50 percent of the 
voting securities, or instruments of ownership, or other forms of 
ownership, of another person constitutes control. Ownership of less 
than 10 percent constitutes a presumption of noncontrol that MMS may 
rebut.
    (2) If there is ownership or common ownership of between 10 and 50 
percent of the voting securities or instruments of ownership, or other 
forms of ownership, of another person, MMS will consider the following 
factors in determining whether there is control under the circumstances 
of a particular case:
    (i) The extent to which there are common officers or directors;
    (ii) With respect to the voting securities, or instruments of 
ownership, or other forms of ownership: the percentage of ownership or 
common ownership, the relative percentage of ownership or common 
ownership compared to the percentage(s) of ownership by other persons, 
whether a person is the greatest single owner, or whether there is an 
opposing voting bloc of greater ownership;
    (iii) Operation of a lease, plant, or other facility;
    (iv) The extent of participation by other owners in operations and 
day-to-day management of a lease, plant, or other facility; and
    (v) Other evidence of power to exercise control over or common 
control with another person.
    (3) Regardless of any percentage of ownership or common ownership, 
relatives, either by blood or marriage, are affiliates.
    ANS means Alaska North Slope (ANS).
    Area means a geographic region at least as large as the limits of 
an oil field, in which oil has similar quality, economic, and legal 
characteristics.
    Arm's-length contract means a contract or agreement between 
independent persons who are not affiliates and who have opposing 
economic interests regarding that contract. To be considered arm's 
length for any production month, a contract must satisfy this 
definition for that

[[Page 14089]]

month, as well as when the contract was executed.
    Audit means a review, conducted under generally accepted accounting 
and auditing standards, of royalty payment compliance activities of 
lessees, designees or other persons who pay royalties, rents, or 
bonuses on Federal leases.
    BLM means the Bureau of Land Management of the Department of the 
Interior.
    Condensate means liquid hydrocarbons (normally exceeding 40 degrees 
of API gravity) recovered at the surface without processing. Condensate 
is the mixture of liquid hydrocarbons resulting from condensation of 
petroleum hydrocarbons existing initially in a gaseous phase in an 
underground reservoir.
    Contract means any oral or written agreement, including amendments 
or revisions, between two or more persons, that is enforceable by law 
and that with due consideration creates an obligation.
    Designee means the person the lessee designates to report and pay 
the lessee's royalties for a lease.
    Exchange agreement means an agreement where one person agrees to 
deliver oil to another person at a specified location in exchange for 
oil deliveries at another location. Exchange agreements may or may not 
specify prices for the oil involved. They frequently specify dollar 
amounts reflecting location, quality, or other differentials. Exchange 
agreements include buy/sell agreements, which specify prices to be paid 
at each exchange point and may appear to be two separate sales within 
the same agreement. Examples of other types of exchange agreements 
include, but are not limited to, exchanges of produced oil for specific 
types of crude oil (e.g., West Texas Intermediate); exchanges of 
produced oil for other crude oil at other locations (Location Trades); 
exchanges of produced oil for other grades of oil (Grade Trades); and 
multi-party exchanges.
    Field means a geographic region situated over one or more 
subsurface oil and gas reservoirs and encompassing at least the 
outermost boundaries of all oil and gas accumulations known within 
those reservoirs, vertically projected to the land surface. State oil 
and gas regulatory agencies usually name onshore fields and designate 
their official boundaries. MMS names and designates boundaries of OCS 
fields.
    Gathering means the movement of lease production to a central 
accumulation or treatment point on the lease, unit, or communitized 
area, or to a central accumulation or treatment point off the lease, 
unit, or communitized area that BLM or MMS approves for onshore and 
offshore leases, respectively.
    Gross proceeds means the total monies and other consideration 
accruing for the disposition of oil produced. Gross proceeds also 
include, but are not limited to, the following examples:
    (1) Payments for services such as dehydration, marketing, 
measurement, or gathering which the lessee must perform at no cost to 
the Federal Government;
    (2) The value of services, such as salt water disposal, that the 
producer normally performs but that the buyer performs on the 
producer's behalf;
    (3) Reimbursements for harboring or terminaling fees;
    (4) Tax reimbursements, even though the Federal royalty interest 
may be exempt from taxation;
    (5) Payments made to reduce or buy down the purchase price of oil 
to be produced in later periods, by allocating such payments over the 
production whose price the payment reduces and including the allocated 
amounts as proceeds for the production as it occurs; and
    (6) Monies and all other consideration to which a seller is 
contractually or legally entitled, but does not seek to collect through 
reasonable efforts.
    Index pricing means using ANS crude oil spot prices, West Texas 
Intermediate (WTI) crude oil spot prices at Cushing, Oklahoma, or other 
appropriate crude oil spot prices for royalty valuation.
    Index pricing point means the physical location where an index 
price is established in an MMS-approved publication.
    Lease means any contract, profit-share arrangement, joint venture, 
or other agreement issued or approved by the United States under a 
mineral leasing law that authorizes exploration for, development or 
extraction of, or removal of oil or gas--or the land area covered by 
that authorization, whichever the context requires.
    Lessee means any person to whom the United States issues an oil and 
gas lease, an assignee of all or a part of the record title interest, 
or any person to whom operating rights in a lease have been assigned.
    Location differential means an amount paid or received (whether in 
money or in barrels of oil) under an exchange agreement that results 
from differences in location between oil delivered in exchange and oil 
received in the exchange. A location differential may represent all or 
part of the difference between the price received for oil delivered and 
the price paid for oil received under a buy/sell exchange agreement.
    Market center means a major point MMS recognizes for oil sales, 
refining, or transshipment. Market centers generally are locations 
where MMS-approved publications publish oil spot prices.
    Marketable condition means oil sufficiently free from impurities 
and otherwise in a condition a purchaser will accept under a sales 
contract typical for the field or area.
    MMS-approved publication means a publication MMS approves for 
determining ANS spot prices, other spot prices, or location 
differentials.
    Netting means reducing the reported sales value to account for 
transportation instead of reporting a transportation allowance as a 
separate entry on Form MMS-2014.
    Oil means a mixture of hydrocarbons that existed in the liquid 
phase in natural underground reservoirs, remains liquid at atmospheric 
pressure after passing through surface separating facilities, and is 
marketed or used as a liquid. Condensate recovered in lease separators 
or field facilities is oil.
    Outer Continental Shelf (OCS) means all submerged lands lying 
seaward and outside of the area of lands beneath navigable waters as 
defined in Section 2 of the Submerged Lands Act (43 U.S.C. 1301) and of 
which the subsoil and seabed appertain to the United States and are 
subject to its jurisdiction and control.
    Person means any individual, firm, corporation, association, 
partnership, consortium, or joint venture (when established as a 
separate entity).
    Quality differential means an amount paid or received under an 
exchange agreement (whether in money or in barrels of oil) that results 
from differences in API gravity, sulfur content, viscosity, metals 
content, and other quality factors between oil delivered and oil 
received in the exchange. A quality differential may represent all or 
part of the difference between the price received for oil delivered and 
the price paid for oil received under a buy/sell agreement.
    Rocky Mountain Region means the States of Colorado, Montana, North 
Dakota, South Dakota, Utah, and Wyoming, except for those portions of 
the San Juan Basin and other oil-producing fields in the ``Four 
Corners'' area that lie within Colorado and Utah.
    Sale means a contract between two persons where:
    (1) The seller unconditionally transfers title to the oil to the 
buyer and does not retain any related rights such

[[Page 14090]]

as the right to buy back similar quantities of oil from the buyer 
elsewhere;
    (2) The buyer pays money or other consideration for the oil; and
    (3) The parties' intent is for a sale of the oil to occur.
    Spot price means the price under a spot sales contract where:
    (1) A seller agrees to sell to a buyer a specified amount of oil at 
a specified price over a specified period of short duration;
    (2) No cancellation notice is required to terminate the sales 
agreement; and
    (3) There is no obligation or implied intent to continue to sell in 
subsequent periods.
    Tendering program means a producer's 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.
    Trading month means the span of time during which crude oil trading 
occurs and spot prices are determined, generally for deliveries of 
production in the following calendar month. For example, for ANS spot 
prices, the trading month includes all business days in the calendar 
month. For other spot prices, for example, the trading month may 
include the span of time from the 26th of the previous month through 
the 25th of the current month.
    Transportation allowance means a deduction in determining royalty 
value for the reasonable, actual costs of moving oil to a point of sale 
or delivery off the lease, unit area, or communitized area. The 
transportation allowance does not include gathering costs.


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

    (a) The value of oil under this section is the gross proceeds 
accruing to the seller under the arm's-length contract, less applicable 
allowances determined under Secs. 206.110 or 206.111. This value does 
not apply if you exercise an option to use a different value provided 
in paragraph (d)(1) or (d)(2)(i) of this section, or if one of the 
exceptions in paragraph (c) of this section applies. Use this paragraph 
(a) to value oil that:
    (1) You sell under an arm's-length sales contract; or
    (2) You sell or transfer to your affiliate or another person under 
a non-arm's-length contract and that affiliate or person, or another 
affiliate of either of them, then sells the oil under an arm's-length 
contract, unless you exercise the option provided in paragraph 
(d)(2)(i) of this section.
    (b) If you have multiple arm's-length contracts to sell oil 
produced from a lease that is valued under paragraph (a) of this 
section, the value of the oil is the volume-weighted average of the 
values established under this section for each contract for the sale of 
oil produced from that lease.
    (c) This paragraph contains exceptions to the valuation rule in 
paragraph (a) of this section. Apply these exceptions on an individual 
contract basis.
    (1) In conducting reviews and audits, if MMS determines that any 
arm's-length sales contract does not reflect the total consideration 
actually transferred either directly or indirectly from the buyer to 
the seller, MMS may require that you value the oil sold under that 
contract either under Sec. 206.103 or at the total consideration 
received.
    (2) You must value the oil under Sec. 206.103 if MMS determines 
that the value under paragraph (a) of this section does not reflect the 
reasonable value of the production due to either:
    (i) Misconduct by or between the parties to the arm's-length 
contract; or
    (ii) Breach of your duty to market the oil for the mutual benefit 
of yourself and the lessor.
    (A) MMS will not use this provision to simply substitute its 
judgment of the market value of the oil for the proceeds received by 
the seller under an arm's-length sales contract.
    (B) The fact that the price received by the seller under an arm's 
length contract is less than other measures of market price, such as 
index prices, is insufficient to establish breach of the duty to market 
unless MMS finds additional evidence that the seller acted unreasonably 
or in bad faith in the sale of oil from the lease.
    (d)(1) If you enter into an arm's-length exchange agreement, or 
multiple sequential arm's-length exchange agreements, and following the 
exchange(s) you or your affiliate sell(s) the oil received in the 
exchange(s) under an arm's-length contract, then you may use either 
Sec. 206.102(a) or Sec. 206.103 to value your production for royalty 
purposes.
    (i) If you use Sec. 206.102(a), your gross proceeds are the gross 
proceeds under your or your affiliate's arm's-length sales contract 
after the exchange(s) occur(s). You must adjust your gross proceeds for 
any location or quality differential, or other adjustments, you 
received or paid under the arm's-length exchange agreement(s). If MMS 
determines that any arm's-length exchange agreement does not reflect 
reasonable location or quality differentials, MMS may require you to 
value the oil under Sec. 206.103. You may not otherwise use the price 
or differential specified in an arm's-length exchange agreement to 
value your production.
    (ii) When you elect under Sec. 206.102(d)(1) to use Sec. 206.102(a) 
or Sec. 206.103, you must make the same election for all of your 
production from the same unit, communitization agreement, or lease (if 
the lease is not part of a unit or communitization agreement) sold 
under arm's-length contracts following arm's-length exchange 
agreements. You may not change your election more often than once every 
2 years.
    (2)(i) If you sell or transfer your oil production to your 
affiliate and that affiliate or another affiliate then sells the oil 
under an arm's-length contract, you may use either Sec. 206.102(a) or 
Sec. 206.103 to value your production for royalty purposes.
    (ii) When you elect under Sec. 206.102(d)(2)(i) to use 
Sec. 206.102(a) or Sec. 206.103, you must make the same election for 
all of your production from the same unit, communitization agreement, 
or lease (if the lease is not part of a unit or communitization 
agreement) that your affiliates resell at arm's length. You may not 
change your election more often than once every 2 years.
    (e) If you value oil under paragraph (a) of this section:
    (1) MMS may require you to certify that your or your affiliate's 
arm's-length contract provisions include all of the consideration the 
buyer must pay, either directly or indirectly, for the oil.
    (2) You must base value on the highest price the seller can receive 
through legally enforceable claims under the contract.
    (i) If the seller fails to take proper or timely action to receive 
prices or benefits it is entitled to, you must pay royalty at a value 
based upon that obtainable price or benefit. But you will owe no 
additional royalties unless or until the seller receives monies or 
consideration resulting from the price increase or additional benefits, 
if:
    (A) The seller makes timely application for a price increase or 
benefit allowed under the contract;
    (B) The purchaser refuses to comply; and (C) The seller takes 
reasonable documented measures to force purchaser compliance.
    (ii) Paragraph (e)(2)(i) of this section will not permit you to 
avoid your royalty payment obligation where a purchaser fails to pay, 
pays only in part, or pays late. Any contract revisions or amendments 
that reduce prices or benefits to which the seller is entitled

[[Page 14091]]

must be in writing and signed by all parties to the arm's-length 
contract.


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

    This section explains how to value oil that you may not value under 
Sec. 206.102 or that you elect under Sec. 206.102(d) to value under 
this section. First determine whether paragraph (a), (b), or (c) of 
this section applies to production from your lease, or whether you may 
apply paragraph (d) or (e) with MMS approval.
    (a) Production from leases in California or Alaska. Value is the 
average of the daily mean ANS spot prices published in any MMS-approved 
publication during the trading month most concurrent with the 
production month. (For example, if the production month is June, 
compute the average of the daily mean prices using the daily ANS spot 
prices published in the MMS-approved publication for all the business 
days in June.)
    (1) To calculate the daily mean spot price, average the daily high 
and low prices for the month in the selected publication.
    (2) Use only the days and corresponding spot prices for which such 
prices are published.
    (3) You must adjust the value for applicable location and quality 
differentials, and you may adjust it for transportation costs, under 
Sec. 206.112.
    (4) After you select an MMS-approved publication, you may not 
select a different publication more often than once every 2 years, 
unless the publication you use is no longer published or MMS revokes 
its approval of the publication. If you are required to change 
publications, you must begin a new 2-year period.
    (b) Production from leases in the Rocky Mountain Region. This 
paragraph provides methods and options for valuing your production 
under different factual situations.
    (1) If you have an MMS-approved tendering program, value your oil 
under paragraph (b)(2) of this section. If you do not have an MMS-
approved tendering program, you may value your oil under either 
paragraph (b)(3) or paragraph (b)(4) of this section.
    (i) You must apply the same subparagraph of this section to value 
all of your production from the same unit, communitization agreement, 
or lease (if the lease is not part of a unit or communitization 
agreement) that you cannot value under Sec. 206.102 or that you elect 
under Sec. 206.102(d) to value under this section.
    (ii) After you select either paragraph (b)(3) or (b)(4) of this 
section, you may not change to the other method more often than once 
every 2 years, unless the method you have been using is no longer 
applicable and you must apply one of the other paragraphs. If you 
change methods, you must begin a new 2-year period.
    (2) If you have an MMS-approved tendering program, the value of 
production from leases in the area the tendering program covers is the 
highest winning bid price for tendered volumes.
    (i) You must offer and sell at least 30 percent of your production 
from both Federal and non-Federal leases in that area under your 
tendering program.
    (ii) You also must receive at least three bids for the tendered 
volumes from bidders who do not have their own tendering programs that 
cover some or all of the same area.
    (iii) MMS will provide additional criteria for approval of a 
tendering program in its ``Oil and Gas Payor Handbook.''
    (3) Value is the volume-weighted average gross proceeds accruing to 
the seller under your and your affiliates' arm's-length contracts for 
the purchase or sale of production from the field or area during the 
production month. The total volume purchased or sold under those 
contracts must exceed 50 percent of your and your affiliates' 
production from both Federal and non-Federal leases in the same field 
or area during that month. Before calculating the volume-weighted 
average, you must normalize the quality of the oil in your or your 
affiliates' arms-length purchases or sales to the same gravity as that 
of the oil produced from the lease.
    (4) Value is the average of the daily mean spot prices published in 
any MMS-approved publication for WTI crude at Cushing, Oklahoma, during 
the trading month most concurrent with the production month. (For 
example, if the production month is June and the trading month is May 
26--June 25, compute the average of the daily mean prices using the 
daily Cushing spot prices published in the MMS-approved publication for 
all the business days between and including May 26 and June 25.)
    (i) Calculate the daily mean spot price by averaging the daily high 
and low prices for the period in the selected publication.
    (ii) Use only the days and corresponding spot prices for which such 
prices are published.
    (iii) You must adjust the value for applicable location and quality 
differentials, and you may adjust it for transportation costs, under 
Sec. 206.112.
    (iv) After you select an MMS-approved publication, you may not 
select a different publication more often than once every 2 years, 
unless the publication you use is no longer published or MMS revokes 
its approval of the publication. If you are required to change 
publications, you must begin a new 2-year period.
    (5) If you demonstrate to MMS's satisfaction that paragraphs (b)(2) 
through (b)(4) of this section 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.
    (c) Production from leases not located in California, Alaska, or 
the Rocky Mountain Region.
    (1) Value is the average of the daily mean spot prices published in 
any MMS-approved publication:
    (i) 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
    (ii) During the trading month most concurrent with the production 
month. (For example, if the production month is June and the trading 
month is May 26-June 25, compute the average of the daily mean prices 
using the daily spot prices published in the MMS-approved publication 
for all the business days between and including May 26 and June 25 for 
the applicable market center.)
    (2) Calculate the daily mean spot price by averaging the daily high 
and low prices for the period in the selected publication. Use only the 
days and corresponding spot prices for which such prices are published. 
You must adjust the value for applicable location and quality 
differentials, and you may adjust it for transportation costs, under 
Sec. 206.112.
    (3) After you select an MMS-approved publication, you may not 
select a different publication more often than once every 2 years, 
unless the publication you use is no longer published or MMS revokes 
its approval of the publication. If you are required to change 
publications, you must begin a new 2-year period.
    (d) Unavailable or unreasonable index prices. If MMS determines 
that any of the index prices referenced in paragraphs (a), (b), and (c) 
of this section are unavailable or no longer represent reasonable 
royalty value, in any particular case, MMS may establish reasonable 
royalty value based on other relevant matters.
    (e) Production delivered to your refinery and index price is 
unreasonable.

[[Page 14092]]

    (1) Instead of valuing your production under paragraph (a), (b), or 
(c) of this section, you may apply to the MMS Director to establish a 
value representing the market at the refinery if:
    (i) You transport your oil directly to your or your affiliate's 
refinery, or exchange your oil for oil delivered to your or your 
affiliate's refinery; and
    (ii) You must value your oil under this section at an index price; 
and
    (iii) You believe that use of the index price is unreasonable.
    (2) You must provide adequate documentation and evidence 
demonstrating the market value at the refinery. That evidence may 
include, but is not limited to:
    (i) Costs of acquiring other crude oil at or for the refinery;
    (ii) How adjustments for quality, location, and transportation were 
factored into the price paid for other oil;
    (iii) Volumes acquired for and refined at the refinery; and
    (iv) Any other appropriate evidence or documentation that MMS 
requires.
    (3) If the MMS Director establishes a value representing market 
value at the refinery, you may not take an allowance against that value 
under Sec. 206.112(b) unless it is included in the Director's approval.


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

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


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

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


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

    You must place oil in marketable condition and market the oil for 
the mutual benefit of the lessee and the lessor at no cost to the 
Federal Government. If you use gross proceeds under an arm's-length 
contract in determining value, you must increase those gross proceeds 
to the extent that the purchaser, or any other person, provides certain 
services that the seller normally would be responsible to perform to 
place the oil in marketable condition or to market the oil.


Sec. 206.107  How do I request a value determination?

    (a) You may request a value determination from MMS regarding any 
Federal lease oil production. Your request must:
    (1) Be in writing;
    (2) Identify specifically all leases involved, the record title or 
operating rights owners of those leases, and the designees for those 
leases;
    (3) Completely explain all relevant facts. You must inform MMS of 
any changes to relevant facts that occur before we respond to your 
request;
    (4) Include copies of all relevant documents;
    (5) Provide your analysis of the issue(s), including citations to 
all relevant precedents (including adverse precedents); and
    (6) Suggest your proposed valuation method.
    (b) MMS will reply to requests expeditiously. MMS may either:
    (1) Issue a value determination signed by the Assistant Secretary, 
Land and Minerals Management; or
    (2) Issue a value determination by MMS; or
    (3) Inform you in writing that MMS will not provide a value 
determination. Situations in which MMS typically will not provide any 
value determination include, but are not limited to:
    (i) Requests for guidance on hypothetical situations; and
    (ii) Matters that are the subject of pending litigation or 
administrative appeals.
    (c)(1) A value determination signed by the Assistant Secretary, 
Land and Minerals Management, is binding on both you and MMS until the 
Assistant Secretary modifies or rescinds it.
    (2) After the Assistant Secretary issues a value determination, you 
must make any adjustments in royalty payments that follow from the 
determination and, if you owe additional royalties, pay late payment 
interest under 30 CFR 218.54.
    (3) A value determination signed by the Assistant Secretary is the 
final action of the Department and is subject to judicial review under 
5 U.S.C. 701-706.
    (d) A value determination issued by MMS is binding on MMS and 
delegated States with respect to the specific situation addressed in 
the determination unless the MMS (for MMS-issued value determinations) 
or the Assistant Secretary modifies or rescinds it.
    (1) A value determination by MMS is not an appealable decision or 
order under 30 CFR part 290 subpart B.
    (2) If you receive an order requiring you to pay royalty on the 
same basis as the value determination, you may appeal that order under 
30 CFR part 290 subpart B.
    (e) In making a value determination, MMS or the Assistant Secretary 
may use any of the applicable valuation criteria in this subpart.
    (f) A change in an applicable statute or regulation on which any 
value determination is based takes precedence over the value 
determination, regardless of whether the MMS or the Assistant Secretary 
modifies or rescinds the value determination.
    (g) The MMS or the Assistant Secretary generally will not 
retroactively modify or rescind a value determination issued under 
paragraph (d) of this section, 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.
    (h) MMS may make requests and replies under this section available 
to the public, subject to the confidentiality requirements under 
Sec. 206.108.


Sec. 206.108  Does MMS protect information I provide?

    Certain information you submit to MMS regarding valuation of oil, 
including transportation allowances, may be exempt from disclosure. To 
the extent applicable laws and regulations

[[Page 14093]]

permit, MMS will keep confidential any data you submit that is 
privileged, confidential, or otherwise exempt from disclosure. All 
requests for information must be submitted under the Freedom of 
Information Act regulations of the Department of the Interior at 43 CFR 
part 2.


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

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


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

    (a) If you or your affiliate incur transportation costs under an 
arm's-length transportation contract, you may claim a transportation 
allowance for the reasonable, actual costs incurred for transporting 
oil under that contract, except as provided in paragraphs (a)(1) and 
(a)(2) of this section and subject to the limitation in 
Sec. 206.109(c). You must be able to demonstrate that your contract is 
arm's length. You do not need MMS approval before reporting a 
transportation allowance for costs incurred under an arm's-length 
transportation contract.
    (1) If MMS determines that the contract reflects more than the 
consideration actually transferred either directly or indirectly from 
you or your affiliate to the transporter for the transportation, MMS 
may require that you calculate the transportation allowance under 
Sec. 206.111.
    (2) You must calculate the transportation allowance under 
Sec. 206.111 if MMS determines that the consideration paid under an 
arm's-length transportation contract does not reflect the reasonable 
value of the transportation due to either:
    (i) Misconduct by or between the parties to the arm's-length 
contract; or
    (ii) Breach of your duty to market the oil for the mutual benefit 
of yourself and the lessor.
    (A) MMS will not use this provision to simply substitute its 
judgment of the reasonable oil transportation costs incurred by you or 
your affiliate under an arm's-length transportation contract.
    (B) The fact that the cost you or your affiliate incur in an arm's 
length transaction is higher than other measures of transportation 
costs, such as rates paid by others in the field or area, is 
insufficient to establish breach of the duty to market unless MMS finds 
additional evidence that you or your affiliate acted unreasonably or in 
bad faith in transporting oil from the lease.
    (b) If your arm's-length transportation contract includes more than 
one liquid product, and the transportation costs attributable to each 
product cannot be determined from the contract, then you must allocate 
the total transportation costs to each of the liquid products 
transported.
    (1) Your allocation must use the same proportion as the ratio of 
the volume of each product (excluding waste products with no value) to 
the volume of all liquid products (excluding waste products with no 
value).
    (2) You may not claim an allowance for the costs of transporting 
lease production that is not royalty-bearing.
    (3) You may propose to MMS a cost allocation method on the basis of 
the values of the products transported. MMS will approve the method 
unless it is not consistent with the purposes of the regulations in 
this subpart.
    (c) If your arm's-length transportation contract includes both 
gaseous and liquid products, and the transportation costs attributable 
to each product cannot be determined from the contract, then you must 
propose an allocation procedure to MMS.
    (1) You may use your proposed procedure to calculate a 
transportation allowance until MMS accepts or rejects your cost 
allocation. If MMS rejects your cost allocation, you must amend your 
Form MMS-2014 for the months that you used the rejected method and pay 
any additional royalty and interest due.
    (2) You must submit your initial proposal, including all available 
data, within 3 months after first claiming the allocated deductions on 
Form MMS-2014.
    (d) If your payments for transportation under an arm's-length 
contract are not on a dollar-per-unit basis, you must convert whatever 
consideration is paid to a dollar-value equivalent.
    (e) If your arm's-length sales contract includes a provision 
reducing the contract price by a transportation factor, do not 
separately report the transportation factor as a transportation 
allowance on Form MMS-2014.
    (1) You may use the transportation factor in determining your gross 
proceeds for the sale of the product.
    (2) You must obtain MMS approval before claiming a transportation 
factor in excess of 50 percent of the base price of the product.


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

    (a) If you or your affiliate have a non-arm's-length transportation 
contract or no contract, including those situations where you or your 
affiliate perform your

[[Page 14094]]

own transportation services, calculate your transportation allowance 
based on your or your affiliate's reasonable, actual transportation 
costs using the procedures provided in this section.
    (b) Base your transportation allowance for non-arm's-length or no-
contract situations on your or your affiliate's actual costs for 
transportation during the reporting period, including:
    (1) Operating and maintenance expenses under paragraphs (d) and (e) 
of this section;
    (2) Overhead under paragraph (f) of this section;
    (3) Depreciation under paragraphs (g) and (h) of this section;
    (4) A return on undepreciated capital investment under paragraph 
(i) of this section; and
    (5) Once the transportation system has been depreciated below ten 
percent of total capital investment, a return on ten percent of total 
capital investment under paragraph (j) of this section.
    (c) Allowable capital costs are generally those for depreciable 
fixed assets (including costs of delivery and installation of capital 
equipment) which are an integral part of the transportation system.
    (d) Allowable operating expenses include:
    (i) Operations supervision and engineering;
    (ii) Operations labor;
    (iii) Fuel;
    (iv) Utilities;
    (v) Materials;
    (vi) Ad valorem property taxes;
    (vii) Rent;
    (viii) Supplies; and
    (ix) Any other directly allocable and attributable operating 
expense which you can document.
    (e) Allowable maintenance expenses include:
    (i) Maintenance of the transportation system;
    (ii) Maintenance of equipment;
    (iii) Maintenance labor; and
    (iv) Other directly allocable and attributable maintenance expenses 
which you can document.
    (f) Overhead directly attributable and allocable to the operation 
and maintenance of the transportation system is an allowable expense. 
State and Federal income taxes and severance taxes and other fees, 
including royalties, are not allowable expenses.
    (g) To compute depreciation, you may elect to use either a 
straight-line depreciation method based on the life of equipment or on 
the life of the reserves which the transportation system services, or a 
unit-of-production method. After you make an election, you may not 
change methods without MMS approval. You may not depreciate equipment 
below a reasonable salvage value.
    (h) This paragraph describes the basis for your depreciation 
schedule.
    (1) If you or your affiliate own a transportation system on June 1, 
2000, you must base your depreciation schedule used in calculating 
actual transportation costs for production after June 1, 2000, on your 
total capital investment in the system (including your original 
purchase price or construction cost and subsequent reinvestment).
    (2) If you or your affiliate purchased the transportation system at 
arm's length before June 1, 2000, you must incorporate depreciation on 
the schedule based on your purchase price (and subsequent reinvestment) 
into your transportation allowance calculations for production after 
June 1, 2000, beginning at the point on the depreciation schedule 
corresponding to that date. You must prorate your depreciation for 
calendar year 2000 by claiming part-year depreciation for the period 
from June 1, 2000 until December 31, 2000. You may not adjust your 
transportation costs for production before June 1, 2000, using the 
depreciation schedule based on your purchase price.
    (3) If you are the original owner of the transportation system on 
June 1, 2000, or if you purchased your transportation system before 
March 1, 1988, you must continue to use your existing depreciation 
schedule in calculating actual transportation costs for production in 
periods after June 1, 2000.
    (4) If you or your affiliate purchase a transportation system at 
arm's length from the original owner after June 1, 2000, you must base 
your depreciation schedule used in calculating actual transportation 
costs on your total capital investment in the system (including your 
original purchase price and subsequent reinvestment). You must prorate 
your depreciation for the year in which you or your affiliate purchased 
the system to reflect the portion of that year for which you or your 
affiliate own the system.
    (5) If you or your affiliate purchase a transportation system at 
arm's length after June 1, 2000, from anyone other than the original 
owner, you must assume the depreciation schedule of the person who 
owned the system on June 1, 2000.
    (i)(1) To calculate a return on undepreciated capital investment, 
multiply the remaining undepreciated capital balance as of the 
beginning of the period for which you are calculating the 
transportation allowance by the rate of return provided in paragraph 
(i)(2) of this section.
    (2) The rate of return is the industrial bond yield index for 
Standard and Poor's BBB rating. Use the monthly average rate published 
in ``Standard and Poor's Bond Guide'' for the first month of the 
reporting period for which the allowance applies. Calculate the rate at 
the beginning of each subsequent transportation allowance reporting 
period.
    (j)(1) After a transportation system has been depreciated at or 
below a value equal to ten percent of your total capital investment, 
you may continue to include in the allowance calculation a cost equal 
to ten percent of your total capital investment in the transportation 
system multiplied by a rate of return under paragraph (i)(2) of this 
section.
    (2) You may apply this paragraph to a transportation system that 
before June 1, 2000, was depreciated at or below a value equal to ten 
percent of your total capital investment.
    (k) Calculate the deduction for transportation costs based on your 
or your affiliate's cost of transporting each product through each 
individual transportation system. Where more than one liquid product is 
transported, allocate costs consistently and equitably to each of the 
liquid products transported. Your allocation must use the same 
proportion as the ratio of the volume of each liquid product (excluding 
waste products with no value) to the volume of all liquid products 
(excluding waste products with no value).
    (1) You may not take an allowance for transporting lease production 
that is not royalty-bearing.
    (2) You may propose to MMS a cost allocation method on the basis of 
the values of the products transported. MMS will approve the method if 
it is consistent with the purposes of the regulations in this subpart.
    (l)(1) Where you transport both gaseous and liquid products through 
the same transportation system, you must propose a cost allocation 
procedure to MMS.
    (2) You may use your proposed procedure to calculate a 
transportation allowance until MMS accepts or rejects your cost 
allocation. If MMS rejects your cost allocation, you must amend your 
Form MMS-2014 for the months that you used the rejected method and pay 
any additional royalty and interest due.
    (3) You must submit your initial proposal, including all available 
data, within 3 months after first claiming the allocated deductions on 
Form MMS-2014.

[[Page 14095]]

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

    When you use index pricing to calculate the value of production 
under Sec. 206.103, you must adjust the index price for location and 
quality differentials and you may adjust it for certain transportation 
costs, as specified in this section.
    (a) If you dispose of your production under one or more arm's-
length exchange agreements, then each of the conditions in this 
paragraph applies.
    (1) You must adjust the index price for location/quality 
differentials. You must determine those differentials from each of your 
arm's-length exchange agreements applicable to the exchanged oil.
    (i) Therefore, for example, if you exchange 100 barrels of 
production from a given lease under two separate arm's-length exchange 
agreements for 60 barrels and 40 barrels respectively, separately 
determine the location/quality differential under each of those 
exchange agreements, and apply each differential to the corresponding 
index price.
    (ii) As another example, if you produce 100 barrels and exchange 
that 100 barrels three successive times under arm's-length agreements 
to obtain oil at a final destination, total the three adjustments from 
those exchanges to determine the adjustment under this subparagraph. 
(If one of the three exchanges was not at arm's length, you must 
request MMS approval under paragraph (b) of this section for the 
location/quality adjustment for that exchange to determine the total 
location/quality adjustment for the three exchanges.) You also could 
have a combination of these examples.
    (2) You may adjust the index price for actual transportation costs, 
determined under Sec. 206.110 or Sec. 206.111:
    (i) From the lease to the first point where you give your oil in 
exchange; and
    (ii) From any intermediate point where you receive oil in exchange 
to another intermediate point where you give the oil in exchange again; 
and
    (iii) From the point where you receive oil in exchange and 
transport it without further exchange to a market center, or to a 
refinery that is not at a market center.
    (b) For non-arm's-length exchange agreements, you must request 
approval from MMS for any location/quality adjustment.
    (c) If you transport lease production directly to a market center 
or to an alternate disposal point (for example, your refinery), you may 
adjust the index price for your actual transportation costs, determined 
under Sec. 206.110 or Sec. 206.111.
    (d) If you adjust for location/quality or transportation costs 
under paragraphs (a), (b), or (c) of this section, also adjust the 
index price for quality based on premia or penalties determined by 
pipeline quality bank specifications at intermediate commingling points 
or at the market center. Make this adjustment only if and to the extent 
that such adjustments were not already included in the location/quality 
differentials determined from your arm's-length exchange agreements.
    (e) For leases in the Rocky Mountain Region, for purposes of this 
section, the term ``market center'' means Cushing, Oklahoma, unless MMS 
specifies otherwise through notice published in the Federal Register.
    (f) If you cannot determine your location/quality adjustment under 
paragraph (a) or (c) of this section, you must request approval from 
MMS for any location/quality adjustment.
    (g) You may not use any transportation or quality adjustment that 
duplicates all or part of any other adjustment that you use under this 
section.


Sec. 206.113  How will MMS identify market centers?

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


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

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


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

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


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

    (a) If you or your affiliate net a transportation allowance rather 
than report it as a separate entry against the royalty value on Form 
MMS-2014, you will be assessed an amount up to 10 percent of the netted 
allowance, not to exceed $250 per lease selling arrangement per sales 
period.
    (b) If you or your affiliate deduct a transportation allowance on 
Form MMS-2014 that exceeds 50 percent of the value of the oil 
transported without obtaining MMS's prior approval under Sec. 206.109, 
you must pay interest on the excess allowance amount taken from the 
date that amount is taken to the date you or your affiliate file an 
exception request that MMS approves. If you do not file an exception 
request, or if MMS does not approve your request, you must pay interest 
on the excess allowance amount taken from the date that amount is taken 
until the date you pay the additional royalties owed.


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

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

[[Page 14096]]

credit plus interest under applicable rules.


Sec. 206.118  Are actual or theoretical losses permitted as part of a 
transportation allowance?

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


Sec. 206.119  How are royalty quantity and quality determined?

    (a) Compute royalties based on the quantity and quality of oil as 
measured at the point of settlement approved by BLM for onshore leases 
or MMS for offshore leases.
    (b) If the value of oil determined under this subpart is based upon 
a quantity or quality different from the quantity or quality at the 
point of royalty settlement approved by the BLM for onshore leases or 
MMS for offshore leases, adjust the value for those differences in 
quantity or quality.
    (c) You may not claim a deduction from the royalty volume or 
royalty value for actual or theoretical losses except as provided in 
Sec. 206.118. Any actual loss that you may incur before the royalty 
settlement metering or measurement point is not subject to royalty if 
BLM or MMS, as appropriate, determines that the loss is unavoidable.
    (d) Except as provided in paragraph (b) of this section, royalties 
are due on 100 percent of the volume measured at the approved point of 
royalty settlement. You may not claim a reduction in that measured 
volume for actual losses beyond the approved point of royalty 
settlement or for theoretical losses that are claimed to have taken 
place either before or after the approved point of royalty settlement.


Sec. 206.120  How are operating allowances determined?

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


Sec. 206.121  Is there any grace period for reporting and paying 
royalties after this subpart becomes effective?

    You may adjust royalties reported and paid for the three production 
months beginning June 1, 2000, without liability for late payment 
interest. This section applies only if the adjustment results from 
systems changes needed to comply with new requirements imposed under 
this subpart that were not requirements under the predecessor rule.

[FR Doc. 00-6049 Filed 3-14-00; 8:45 am]
BILLING CODE 4310-MR-P