# Establishing Oil Value for Royalty Due on Federal Leases

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URL: https://www.frixlaw.com/law-library/documents/fr%3A00-6049

## Record

- **Collection:** Federal Register
- **Document type:** Rule
- **Published:** March 15, 2000
- **Citation:** 65 FR 14022

## Text

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.

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 david.guzy@mms.gov.

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

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

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.

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

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 § 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

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 § 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

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 § 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

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

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

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.

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 § 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 §§ 206.112 and 206.113 in the February 1998 proposal, which are now adopted as § 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 § 206.110 or § 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 § 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 § 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

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

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

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

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 § 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 § 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

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 § 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 § 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 § 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.

(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

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 a

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Source: Frix Law Library, https://www.frixlaw.com/law-library/documents/fr%3A00-6049. Public record. Not legal advice.