04-16725. Federal Gas Valuation

AGENCY:

Minerals Management Service (MMS), Interior.

ACTION:

Proposed rule.

SUMMARY:

The MMS is proposing to amend the existing regulations governing the valuation of gas for royalty purposes produced from Federal leases. The current regulations became effective on March 1, 1988, and were amended in relevant respects in 1996 and 1998.

In continuing to evaluate the effectiveness and efficiency of its rules, MMS has identified certain issues that warrant proposal and public comment. These issues primarily concern calculation of transportation costs (including the allowed rate of return in calculation of actual transportation costs in non-arm's-length transportation arrangements, and further specific itemization of allowable and non-allowable costs), revision or simplification of certain provisions, and changes necessitated by judicial decisions in subsequent litigation. The MMS is proposing some changes to be consistent with analogous provisions of the recently-amended Federal crude oil valuation rule.

DATES:

Comments must be submitted on or before September 21, 2004.

ADDRESSES:

Address your comments, suggestions, or objections regarding this proposed rule to:

By regular U.S. Mail. Minerals Management Service, Minerals Revenue Management, Chief of Staff, P.O. Box 25165, MS 302B2, Denver, Colorado 80225-0165; or

By overnight mail or courier. Minerals Management Service, Minerals Revenue Management, Building 85, Room A-614, Denver Federal Center, Denver, Colorado 80225; or

By e-mail. [e-mail]. Please submit Internet comments as an ASCII file and avoid the use of special characters and any form of encryption. Also, please include “Attn: RIN 1010-AD05” and your name and return address in your Internet message. If you do not receive a confirmation that we have received your Internet message, call the contact person listed below.

FOR FURTHER INFORMATION CONTACT:

Sharron L. Gebhardt, Lead Regulatory Specialist, Minerals Revenue Management, MMS, telephone [phone], fax [phone], or e-mail [e-mail]. The principal authors of this rule are Geoffrey Heath of the Office of the Solicitor and Larry E. Cobb and Susan Lupinski of Minerals Revenue Management, MMS, Department of the Interior.

SUPPLEMENTARY INFORMATION:

I. Background

The MMS is proposing to amend the existing regulations at 30 CFR 206.150 et seq. governing the valuation of gas for royalty purposes produced from Federal leases. The MMS conducted four public workshops from April 23 through May 1, 2003, in Denver, Colorado; Albuquerque, New Mexico; Houston, Texas; and Washington, DC. At those workshops, MMS asked for discussion regarding, among other things, royalty treatment of non-arm's-length dispositions (including possible use of New York Mercantile Exchange (NYMEX) prices or spot market index prices in place of the current “benchmarks” for valuing gas not sold under arm's-length contracts), greater specificity regarding allowable transportation costs, the rate of return used in calculating actual transportation costs, and the royalty effect of sales under joint operating agreements. After considering the input from these workshops, MMS is proposing these amendments in an effort to improve the current rule. The amendments proposed do not alter the basic structure or underlying principles of the current rule.

II. Explanation of Proposed Amendments

Comments at the workshops on major valuation issues—such as using spot market index prices or NYMEX prices to value gas not sold under arm's-length contracts, treatment of affiliate resales, and joint operating agreements—were in some cases somewhat sparse, and in other cases quite polarized. Due to the disparity of comments and concerns expressed at the workshops about publicly available spot market prices for natural gas, we have decided that we are not ready to propose new rules on some of these issues at this time. The MMS is continuing to evaluate these issues but will not address them in this proposed rule. For future consideration, we request current public comment on (1) whether publicly available spot market prices for natural gas are reliable and representative of market value of natural gas and should be considered by MMS as a means of valuing natural gas production that is not sold at arm's-length and, if so, (2) how should these spot market prices be adjusted for location differences between the index pricing point and the lease.

On other matters, however, comments indicated that proposed changes were appropriate. For example, MMS adopted a final rule amending the Federal crude oil royalty valuation regulations that became effective in June 2000. 65 FR 10422. Some of these proposed changes for the gas valuation rules would conform to what MMS adopted for crude oil in June 2000. In addition, there are certain issues, on which MMS did not specifically request comments at the workshops, for which proposed changes are appropriate, particularly in light of both recent judicial decisions and the recently-amended Federal crude oil valuation rule (69 FR 24959, May 5, 2004). This proposal addresses issues in the latter categories.

The explanation of the proposed changes will proceed in order according to the section number in the current rule (30 CFR part 206 subpart D) for which amendment(s) are proposed.

A. Section 206.150—Purpose and Scope

The MMS is proposing to amend §206.150(b) by separating it into subparagraphs and adding a new subparagraph (3). The new subparagraph (3) would provide that if a written agreement between the lessee and the MMS Director establishes a production valuation method for any lease that MMS expects at least would approximate the value otherwise established under this subpart, the written agreement will govern to the extent of any inconsistency with the regulations. This provision is intended to provide flexibility to both MMS and the lessee in those few unusual circumstances where a separate written agreement is reached, while at the same time maintaining the integrity of the regulations. As noted, any such agreement also must at least approximate the royalty value for the production that would apply under these regulations.

This proposed amendment is identical to 30 CFR 206.100(d) in the Federal crude oil valuation rule amended in June 2000. The MMS has used the provision in the crude oil regulation to address a few unexpectedly difficult royalty valuation problems. The MMS believes that if this option is useful to lessees and the MMS Director in the context of crude oil royalty valuation, it likewise should be available for gas valuation.

B. Section 206.151—Definitions

The MMS proposes to add a definition of the term “affiliate” and revise the definition of the term “arm's-length contract” to be identical to the June 2000 Federal crude oil valuation rule and to conform the gas valuation rule with the D.C. Circuit's holding in National Mining Association v. Department of the Interior, 177 F.3d 1 (D.C. Cir. 1999). As in the 2000 Federal crude oil rule, MMS is proposing to define the term “affiliate” separately from the term “arm's-length contract.” We believe this clarifies and simplifies the definitions and should promote better understanding of both “arm's-length contract” and “affiliate.” For a full explanation of the reasons for this proposed change to the definitions, see the discussion in the preamble to the June 2000 final crude oil valuation rule at 65 FR 14022, at 14039-14040 (Mar. 15, 2000).

The MMS also proposes to revise the definition of “transportation allowance,” which is part of the term “allowance.” In the 1988 rule, the term “transportation allowance” (within the term “allowance”) was defined as follows:

Transportation allowance means an allowance for the reasonable, actual costs incurred by the lessee for moving unprocessed gas, residue gas, or gas plant products to a point of sale or point of delivery off the lease, unit area, communitized area, or away from a processing plant, excluding gathering, or an approved or MMS-initially accepted deduction for costs of such transportation, determined pursuant to this subpart.

30 CFR 206.151 (1988-1995). In 1996, the definition was changed to the current definition, which reads as follows:

Transportation allowance means an allowance for the cost of moving royalty bearing substances (identifiable, measurable oil and gas, including gas that is not in need of initial separation) from the point at which it is first identifiable and measurable to the sales point or other point where value is established under this subpart.

30 CFR 206.151 (1996-2003) (promulgated at 61 FR 5448, at 5464 (Feb. 12, 1996)). The principal purpose of the 1996 rulemaking was to eliminate various form filing requirements in connection with transportation and processing allowances for Federal leases, and, in that connection, to separate the valuation rules applicable to Indian leases from the rules applicable to Federal leases. 61 FR at 5448. The only statement in the preamble to the 1996 rule regarding the definition of “allowance” was as follows:

Allowance. We changed the definition to remove any implication of a forms filing requirement, or of having to seek MMS approval prior to claiming an allowance on Form MMS-2014.

61 FR at 5451. While this reason may be relevant to eliminating the words “or an approved or MMS-initially accepted deduction for costs of such transportation” in the 1988 rule's definition, it has no apparent relevance to the other changes in the wording of the definition, for which no explanation at all was given in the preamble.

Indeed, the proposed rule, published on August 7, 1995, at 60 FR at 40127, did not even propose a change to the definition of “allowance” or of “transportation allowance” at all. Nor did it ask for comments on the allowance definitions.

The only reference to the language promulgated in 1996 in any previous Federal Register notice was in a November 6, 1995 proposed rule (60 FR at 56007). That proposal grew out of discussions with States and industry regarding possible major changes in gas valuation methodology. The November 1995 proposal was not related to the changes in the allowance form filing requirements, and was not part of the origins of the February 1996 final rule. The November 1995 proposed rule included a number of interrelated changes. One of them was a change in the definition of “transportation allowance” that was identical to the language found in the February 1996 final rule on allowance form filing requirements. The November 1995 proposed rule was never finalized, and MMS formally withdrew it on April 22, 1997 (62 FR at 19536).

There is no explanation in the preamble to the February 1996 final rulemaking of why or how the definition from the unrelated November 1995 proposal found its way into the February 1996 final rule on allowance form filing requirements. There is no indication in any of the Federal Register notices in connection with the February 1996 final rulemaking of any intent to change the definition of “transportation allowance.” Nor did the February 1996 final rule include any other provisions from the unrelated November 1995 proposal, including provisions that were related to the definition of “transportation allowance” in that proposal. The 1996 change in the wording of the definition appears to have been an inadvertent clerical mistake. In practice, both industry and MMS have continued to conduct business since 1996 on the basis that the substantive definition of “transportation allowance” has remained unchanged. That practice and course of conduct correctly reflect the underlying intent of the existing rules.

To correct any ambiguity, MMS is proposing to amend the definition of “transportation allowance” to be consistent with the June 2000 Federal crude oil valuation rule, with necessary changes in wording to apply it in the gas context. The proposed definition reads as follows:

Transportation allowance means an allowance for the reasonable, actual costs of moving unprocessed gas, residue gas, or gas plant products to a point of sale or delivery off the lease, unit area, or communitized area, or away from a processing plant. The transportation allowance does not include gathering costs.

This proposed change also returns the definition to being substantively the same as the original 1988 rule's definition.

Finally, MMS proposes to add the word “actual” before the word “costs” in the definition of “processing allowance.” The February 1996 final rule on allowance form filing requirements deleted that word with no explanation. The proposed change restores the pre-1996 wording and makes the wording of this definition consistent with wording of other allowance definitions. MMS does not intend to change the meaning of the term “processing allowance” in any respect.

C. Section 206.157—Determination of Transportation Allowances

The MMS is proposing a number of changes and technical corrections to this section. First, MMS proposes to change the allowed rate of return in § 206.157(b)(2)(v) used in calculating transportation costs for non-arm's-length transportation arrangements. Under § 206.157(b)(2), the lessee has a choice of two methods for calculating transportation costs. The first method allows the lessee to use its operating and maintenance expenses, overhead, depreciation, and a rate of return on its undepreciated capital investment. Under the second method, the lessee may use its operating and maintenance expenses, overhead, and a rate of return on its initial investment. The MMS proposes to change the allowable rate of return used in both of these calculation methods.

The rate of return in the current § 206.157(b)(2) is the industrial rate associated with the Standard and Poor's BBB rating. The MMS believed that this rate represented an intermediate rate fairly reflective of the industry's overall cost of money necessary to construct transportation facilities (principally through debt financing). The MMS proposes to increase that rate to 1.3 times the rate associated with the BBB rating.

The reason for proposing this rate is a recent MMS, Offshore Minerals Management, Economics Division study of gas pipeline costs of capital. The study examined Energy Information Administration (EIA) published returns on investment for 2000-2001 for firms engaged in the pipeline business, which is one indicator of the cost of capital. The MMS study also examined cost of capital data for gas pipelines and distributors published by Ibbotson for the first quarter of 2003. The EIA data indicated that the average rate of return for firms in the pipeline business approximated the BBB rate, and that most pipelines have a BBB rating for their debt capital. The Ibbotson data showed a cost of capital range for gas pipelines and distributors between 1.1 times BBB and 1.5 times BBB. (The MMS study also discusses a recent American Petroleum Institute (API) research paper that took the approach that a weighted average cost of debt and equity represents the true cost of capital for non-independent pipelines. The API paper finds a ratio of weighted average cost of capital to the BBB bond rate of between 1.6 and 1.8. However, the API paper appears to be based on the weighted average cost of capital for the oil production industry as opposed to the gas pipeline industry.)

Based on the assumptions underlying the Ibbotson range of findings that MMS's study believed were most accurate, it found 1.3 times BBB to be the most appropriate. The MMS therefore is proposing this rate. This is also the rate that MMS adopted in its recently-amended Federal crude oil valuation rule (69 FR 24959, May 5, 2004). The MMS seeks comments regarding the proper rate of return and supporting data and analysis.

The MMS recognizes that some industry commenters in three of the workshops recommended that the same rate of return that applies in non-arm's-length transportation cost calculations also should apply in non-arm's-length processing cost calculations. The processing cost regulations at 30 CFR 206.159(b)(2)(v) also allow for a rate of return equal to the Standard & Poor's BBB bond rate. However, MMS is not proposing a change in the rate of return for non-arm's-length processing cost calculations at this time because the MMS study did not extend to gas processing plant costs. The MMS welcomes comments, data, and analysis on that issue. If MMS obtains sufficient information and data through the comment process to support a change, it may change the rate of return used in non-arm's-length processing cost calculations in the final rule.

The MMS proposes to rewrite § 206.157(b)(5). This provision allows lessees to apply for an exception to the requirement to calculate actual costs in non-arm's-length transportation situations if the lessee has a tariff approved by the Federal Energy Regulatory Commission (FERC) or a State regulatory agency. The provision as currently written then adds a number of conditions that are difficult to interpret. The MMS's experience has been that these conditions have been difficult to apply and are burdensome on the lessees. (For example, the lessee must calculate actual costs before it can claim the exception from the requirement to calculate actual costs under some circumstances (i.e., if there are no arm's-length transportation charges to use for comparison, and if no FERC or state regulatory agency cost analysis exists, and if FERC or the state regulatory agency declines to investigate after a timely MMS objection).) The underlying concept that the current provision is meant to embody is that if a regulatory agency has either adjudicated a particular tariff for a transportation system (to resolve an objection to the tariff as filed) or has analyzed the tariff (if there is no objection filed) and found it to be a just and reasonable rate, the lessee should be able to use it as the basis for its transportation allowance as long as the tariff rate is still consistent with actual market conditions. The current wording, however, does not necessarily accomplish this objective.

The MMS proposes to simplify §206.157(b)(5) by rewriting it as follows:

You may apply for an exception from the requirement to compute actual costs under paragraphs (b)(1) through (b)(4) of this section.

(i) The MMS will grant the exception if (A) the transportation system has a tariff approved by the Federal Energy Regulatory Commission (FERC) or a state regulatory agency that FERC or the state regulatory agency has either adjudicated or specifically analyzed, and (B) third parties are actually paying prices under the tariff to transport gas on the system under arm's-length transportation contracts.

(ii) If MMS approves the exception, you must calculate your transportation allowance for each production month based on the volume-weighted average of the rates paid by the third parties under arm's-length transportation contracts during that production month. If during any production month there are no prices paid under the tariff by third parties to transport gas on the system under arm's-length transportation contracts, you may use the volume-weighted average of the rates paid by third parties under arm's-length transportation contracts in the most recent preceding production month in which third parties paid such rates, for up to two successive production months.

(iii) You may use the exception under this paragraph if the tariff remains in effect and no more than two production months have elapsed since third parties paid prices under the tariff to transport gas on the system under arm's-length transportation contracts.

Under this proposal, if a transportation system with which the lessee is affiliated has an approved tariff that has been either adjudicated or specifically analyzed, and if there are currently arm's-length shippers on that system, then the lessee would not have to calculate actual costs. But the allowance would not necessarily be the maximum tariff rate. Instead, it would be the volume-weighted average of the arm's-length rates charged to the non-affiliated shippers. This would avoid the potential for the lessee to claim a transportation allowance that exceeds the market transportation rates actually charged to arm's-length shippers.

The proposed provision also covers situations (which MMS anticipates would be rare) in which there is a short gap of one or two production months in which there are no arm's-length prices paid by third parties to transport gas on the system. Such a situation might arise if there were very few arm's-length third-party shippers, and the third party shippers temporarily were without contracts to sell their gas. In that event, the proposed rule would allow the lessee to use the volume-weighted average of the rates paid by third parties under arm's-length transportation contracts in the most recent preceding production month in which third parties paid such rates, for up to two successive production months, during the “gap” period. If there are no arm's-length transportation rates charged to unaffiliated shippers for more than two successive production months, the lessee would not be able to use the exception and would have to calculate actual costs. Similarly, the lessee would have to calculate actual costs if the tariff expires.

Further, the mere filing of a tariff with FERC or a State regulatory agency is not sufficient for a lessee to invoke the exception. The tariff must either be adjudicated, or, if no party files an objection to a filed tariff, it must be specifically analyzed by either FERC or the State regulatory agency.

The MMS also proposes to amend § 206.157(c) in several respects. First, the proposal would eliminate the requirement that the lessee report its transportation allowance using a separate line entry on the Form MMS-2014. That requirement is no longer relevant because the Form MMS-2014 has been revised. While the transportation allowance is still reported in a discrete field, it is not strictly on a separate line from associated sales transaction data. The proposal would revise the regulation accordingly.

Second, the wording of the proposed new paragraph (c) would make it consistent with the analogous provisions of the June 2000 Federal crude oil valuation rule at §§ 206.114 and 206.115.

Third, the proposed rule would add new paragraphs (c)(1)(iii) and (c)(2)(v) to expressly clarify that allowances that were in effect when the 1988 valuation rule became effective and that were “grandfathered” under the former §§206.157(c)(1)(v) and 206.157(c)(2)(v) have been terminated. Paragraphs (c)(1)(v) and (c)(2)(v) were removed by the February 1996 rule discussed above. See 61 FR at 5451. Because of the very limited explanation for that removal and the fact that removal of these clauses was not specifically mentioned in the August 1995 proposed rule, disputes have arisen regarding the continued validity after March 1996 of pre-1988 allowances that had continued in effect under the “grandfathering” provisions. The MMS reaffirms its view that the pre-1988 allowances were terminated effective March 1, 1996, when the “grandfathering” provisions were removed. But regardless of the outcome of disputes as to the continued validity of “grandfathered” allowances between 1996 and the present, MMS proposes to specifically clarify that lessees may not use such allowances prospectively.

The proposed rule also would amend § 206.157(f), which identifies allowable costs in determining transportation allowances, in three respects. One proposed change would conform the rule with recent judicial precedent. The other two proposed amendments are analogous to the recently-amended Federal crude oil valuation rule (69 FR 24959, May 5, 2004).

First, MMS proposes to amend 206.157(f)(1) regarding firm demand charges (sometimes called reservation fees). The current rule provides:

Firm demand charges paid to pipelines. You must limit the allowable costs for firm demand charges to the applicable rate per MMBtu multiplied by the actual volumes transported. You may not include any losses incurred for previously purchased but unused firm capacity. You also may not include any gains associated with releasing firm capacity. If you receive a payment or credit from the pipeline for penalty refunds, rate case refunds, or other reasons, you must reduce the firm demand charge claimed on the Form MMS-2014. You must modify the Form MMS-2014 by the amount received or credited for the affected reporting period;

The rule thus prohibits lessees from deducting unused firm demand charges.

Section 206.157(f) was promulgated as part of a rule amendment published on December 16, 1997 (62 FR 65762) (effective February 1, 1998). The 1998 rule amendment specified which of the various costs addressed in and itemized under FERC Order 636 either were deductible or nondeductible in calculating transportation allowances. The producing industry challenged the rule in Independent Petroleum Association of America et al. v. Armstrong, Nos. 1:98CV00531 and 1:98CV00631 (D.D.C.). The primary issue in the litigation was the lessee's duty to market production at no cost to the lessor, which the rule formally codified at 30 CFR 206.152(i) and 206.153(i). But among the other provisions that the producing industry challenged was the prohibition against deducting unused firm demand charges in § 206.157(f)(1).

In IPAA v. Armstrong, the district court initially declared the entire rule unlawful. 91 F. Supp. 2d 117, 130 (D.D.C. 2000). On April 10, 2000, the Federal Government moved to alter or amend the judgment under Rule 59(e), Fed. R. Civ.P. Among other things, the Government explained:

The Court's Order and Final Judgment states that 30 CFR 206.157(f)(1) (Federal leases) and 206.177(f)(1) (Indian leases) are invalidated without further clarification. These sections of the challenged rule allow so-called “firm demand” charges—charges that shippers pay to pipelines to reserve pipeline capacity—to be deducted as transportation costs, but limit the deductibility of these costs to the costs incurred for the actual volumes transported.

In limiting the deductibility of these costs to the actual volumes transported, these provisions correspondingly provide that lessees may not take into account in calculating the allowance “any gains associated with releasing firm capacity”—i.e., selling unused firm capacity to other producer-shippers. In other words, both the cost of unused firm capacity and revenues derived from selling unused firm capacity are disregarded under the rule and are irrelevant in calculating the allowance.

However, the rule does require lessees to reduce the firm demand charge claimed as a transportation allowance by the amount of any payment or credit received from the pipeline. Id. This ensures that, if a lessee in the end pays less than the cost originally paid for transportation and used in calculating the allowance originally reported, the lessee will reduce the earlier transportation cost to prevent the allowance of a deduction for transportation costs which it has not actually paid to the pipeline.^[2]

In their briefs in this case, Plaintiffs challenged MMS' refusal to allow the costs of unused firm capacity as a transportation cost deduction. At pages 24-25 of the Court's Opinion, the Court seems to indicate some belief that disallowance of unused firm demand charges was arbitrary, but there was no further discussion of this provision in the Opinion. The Order and Final Judgment then stated only that the cited paragraphs were invalid.

Consequently, it appears to Defendants that the Court intended to declare 30 CFR 206.157(f)(1) and 206.177(f)(1) unlawful only with regard to that portion of the regulations which disallows a deduction for unused capacity, and not with regard to those additional provisions discussed above. But invalidating the disallowance of unused firm demand charges (and therefore allowing lessees to deduct them as part of transportation costs) necessarily affects the other provisions of these paragraphs. Accordingly, Defendants seek clarification from the Court.

Before the Court's decision here, when unused firm demand charges were disallowed, there correspondingly was no consequence for the allowance calculation if the lessee sold all or part of its unused firm capacity. If lessees now may deduct unused firm demand charges, and report transportation allowances on that basis, it necessarily follows that if a lessee sells unused firm capacity, it must reduce the reported allowance and pay the resulting royalties due. This necessarily follows from the gross proceeds rule. If a lessee initially reported a transportation allowance in an amount greater than its ultimate transportation costs, it must amend its royalty reports and pay the additional royalties.

For these reasons, the attached proposed amended judgment both clarifies which portions of these paragraphs have been held invalid and requires lessees to amend their reports and pay additional royalties if they sell firm capacity the costs of which previously had been included in a reported allowance.

Defendants' Motion to Alter or Amend the Judgment, April 10, 2000, at 4-6. On September 1, 2000 (2000 U.S. Dist. LEXIS 22478), the Court granted the motion to alter or amend, and entered an Amended Order that read in relevant part as follows:

The court hereby declares that the following regulations are unlawful and of no force or effect:

* * * * *

2. Those provisions of 30 CFR 206.157(f)(1) and 206.177(f)(1) to the extent that they limit allowable costs for firm demand charges in determining transportation allowances to the applicable rate per MMBtu multiplied by the actual volumes transported; however, to the extent that a lessee sells unused firm capacity, and if the cost of that unused firm capacity was included in a previously reported transportation allowance, the lessee must amend its royalty reports to reduce the transportation allowance by the revenue derived from the sale of the firm capacity, and pay any resulting royalty and late payment interest due.

Amended Order and Final Judgment, September 1, 2000, at 1-2.

The Government appealed the district court's decision. In Independent Petroleum Association of America v. DeWitt, 279 F.3d 1036 (D.C. Cir. 2002), cert. denied, _U.S. _, 123 S. Ct. 869 (2003), the Court of Appeals for the District of Columbia Circuit reversed the district court on the principal issue in the litigation, the lessee's duty to market production at no cost to the lessor, and upheld the rule generally. However, with respect to firm demand charges, the D.C. Circuit held:

“Unused” firm demand charges. Shippers of natural gas may choose among different degrees of assurance that space will be available for their shipments, paying (naturally) for extra security. By paying a firm demand charge (an upfront reservation fee), they secure a guaranteed amount of continuously available pipeline capacity; when they actually ship, they incur a “commodity charge” for the transport itself. The reservation fee, however, is nonrefundable—the cost of any reserved capacity that a lessee ultimately cannot use will be lost unless it is able to resell the capacity. (Recall that the district court amended the summary judgment order, at the behest of the government, to provide for a credit to the government in the event of such resales.) In contrast, with “interruptible” service, shippers pay no reservation fee, but their access to pipeline capacity is subject to the changing needs of other, higher priority customers (i.e., those who pay for firm demand). Producers claim that the unused firm demand charges are part of their actual transportation costs, and thus should be deductible.

In defense of its contrary view, Interior said only that it does “not consider the amount paid for unused capacity as a transportation cost,” Final Rule, 62 FR at 65757/1, not revealing to what category such expenses did belong. In its opening brief, it quotes its prior assertion and declares that the district court must be reversed because it “offered no cogent reason for rejecting this distinction.” Interior Br. at 43. But Interior has offered no “distinction” at all, only an unusually raw ipse dixit. On its face, it is hard to see how money paid for assurance of secure transportation is not “for transportation”; the cost of freight insurance looks like a shipping expense, for example, even if the goods arrive without difficulty and the premium therefore goes “unused.” And Interior makes no suggestion that producers have incurred such fees extravagantly—an extravagance that seems unlikely, as under the ordinary 1/8 lease the producer would bear 7/8 of the loss. Further, under the crediting arrangement provided by the district court order, the government will share in any recovery of “unused” charge, a recovery that producers have strong incentives to pursue. While some reason may lurk behind the government's position, it has offered none, and we have no basis for sustaining its conclusion. See, e.g., Motor Vehicle Manufacturers Ass'n., Inc. v. State Farm Mut. Auto Ins. Co., 463 U.S. 29, 43 (1983).

The judgment of the district court is reversed on all issues except for its ruling on unused firm demand charges, which we affirm.

279 F.3d at 1042-1043.

The MMS therefore proposes to amend 30 CFR 206.157(f)(1) to conform with the D.C. Circuit's decision, so as to allow lessees to deduct unused firm demand charges, and to provide for reduction of previously reported transportation allowances in the event the lessee sells unused firm capacity after including it as part of that previously reported allowance. The proposed amended provision would read:

(1) Firm demand charges paid to pipelines. You may deduct firm demand charges or capacity reservation fees paid to a pipeline, including charges or fees for unused firm capacity that you have not sold before you report your allowance. If you receive a payment from any party for release or sale of firm capacity after reporting a transportation allowance that included the cost of that unused firm capacity, or if you receive a payment or credit from the pipeline for penalty refunds, rate case refunds, or other reasons, you must reduce the firm demand charge claimed on the Form MMS-2014 by the amount of that payment. You must modify the Form MMS-2014 by the amount received or credited for the affected reporting period, and pay any resulting royalty and late payment interest due;

(2) * * *.

Second, MMS proposes to amend § 206.157(f)(7), addressing actual and theoretical line losses. The current rule prohibits deduction of both actual and theoretical line losses under non-arm's-length transportation arrangements unless the allowance is based on a FERC- or State regulatory-approved tariff. In the recently-amended Federal crude oil valuation rule (69 FR 24959, May 5, 2004), MMS allowed actual, but not theoretical, line losses under non-arm's-length transportation arrangements. As MMS explained in the preamble to that final rule, MMS believes that actual line losses properly may be regarded as a cost of moving production. In addition, if there is a line gain, the lessee must reduce its transportation allowance accordingly. In a non-arm's-length situation, however, a charge for theoretical line losses would be artificial and would not be an actual cost to the lessee. While a lessee may have to pay an amount to a pipeline operator for theoretical line losses as part of an arm's-length tariff, in a non-arm's-length situation, line losses, like other costs, should be limited to actual costs incurred. (However, if a non-arm's-length transportation allowance is based on a FERC- or State regulatory-approved tariff that includes a payment for theoretical line losses, that cost would be allowed, as the current rule already provides.)

The MMS also proposes to amend § 206.157(f) by adding a new paragraph (f)(10) to allow lessees to deduct the costs of securing a letter of credit or other surety that the pipeline requires a shipper to maintain under an arm's-length contract. The MMS recently-amended Federal crude oil valuation rule (69 FR 24959, May 5, 2004) allows this cost in arm's-length situations. The MMS believes that this is a cost that the lessee must incur to obtain the pipeline's transportation service, and therefore is a cost of moving the gas. These costs may include only the costs currently allocable to production from the Federal lease. In non-arm's-length situations, MMS expects that requiring a letter of credit from an affiliated producer is unnecessary and that the corporate organization ordinarily would avoid incurring the costs of the premium necessary for the letter of credit. MMS therefore believes it inappropriate to allow such a deduction.

A surety may take any of several forms—for example, a letter of credit, a bond, or a cash deposit on which a pipeline may draw in the event of nonpayment of transportation charges. To illustrate the principle that the costs may include only the costs of surety that are allocable to the Federal lease or leases, assume hypothetically that you make a cash deposit of 2 months of the expected transportation charges (assume $50,000), and transport 100,000 MMBtu per month, of which 75,000 MMBtu are produced from a Federal lease. You would calculate the cost of the cash deposit in this example as follows:

(i) Calculate the monthly rate of return representing your cost of capital in making the cash deposit. In this example, if the Standard and Poor's BBB rating is 8 percent, the allowable annual rate would be 1.3 × .08 = .104. Divide the annual rate by 12 to obtain a monthly rate. The allowable monthly rate therefore would be .104/12 = .008667.

(ii) Multiply that monthly rate of return by the amount of the deposit ($50,000) to get the monthly cost, which would be $50,000 × .008667 = $433.33.

(iii) Then multiply that result by the proportion of total production that is produced from the Federal lease to calculate the share of that amount applicable to the Federal lease. In this example, the proportion of production applicable to the Federal lease is 75,000 MMBtu/100,000 MMBtu = 3/4. So you could include in your transportation costs $433.33 × .75 = $325 as an allowable transportation cost for as long as the $50,000 is on deposit (and the other factors remain unchanged).

The expense of a letter of credit or other surety would be treated similarly. If you pay a bank $5,000 as a non-refundable fee for a letter of credit, you could include the proportion allocable to Federal production in the month that fee is paid (and then never again), or you may calculate a monthly cost of that $5,000 (similar to calculating the cost of the cash deposit) and include that monthly cost as part of the transportation allowance reported each month for the life of the transportation contract. The MMS welcomes comments on whether these are reasonable ways to calculate the actual costs of sureties that pipelines require from shippers.

The MMS seeks comments regarding whether these various costs should be allowed, and whether there are other costs directly attributable to the transportation of gas that should be included in the final rule.

Finally, MMS proposes to amend § 206.157(g) to add new paragraphs (g)(5), (g)(6), and (g)(7), and to redesignate the current paragraph (g)(5) as paragraph (g)(8), to further specify other costs that are not allowable in determining transportation allowances. These nonallowable costs include:

• Fees paid to brokers. This includes fees paid to parties who arrange marketing or transportation, if such fees are separately identified from aggregator/marketer fees. The MMS believes such fees are marketing costs and are not actual costs of transportation.
• Fees paid to scheduling service providers. This includes fees paid to parties who provide scheduling services, if such fees are separately identified from aggregator/marketer fees. The MMS believes that these costs are marketing or administrative costs that lessees must bear at their own expense and are not actual costs of transportation.
• Internal costs, including salaries and related costs, rent/space costs, office equipment costs, legal fees, and other costs to schedule, nominate, and account for sale or movement of production. These costs never have been deductible, and MMS proposes to expressly reaffirm this principle for clarity.

The recently-amended Federal crude oil valuation rule (69 FR 24959, May 5, 2004) identifies these costs as non-deductible, and the proposal here would make the two rules consistent.

The proposed paragraph (g)(8), addressing “other nonallowable costs,” is the current paragraph (g)(5) renumbered.

The MMS does not believe that any of the above-described costs are incurred as part of the process of physically moving gas. The MMS seeks comments on whether any of these costs should be deductible.

III. Procedural Matters

1. Public Comment Policy

Our practice is to make comments, including names and home addresses of respondents, available for public review during regular business hours and on our Internet site at www.mrm.mms.gov. Individual respondents may request that we withhold their home address from the rulemaking record, which we will honor to the extent allowable by law. There also may be circumstances in which we would withhold from the rulemaking record a respondent's identity, as allowable by law. If you wish us to withhold your name and/or address, you must state this prominently at the beginning of your comments. However, we will not consider anonymous comments. We will make all submissions from organizations or businesses, and from individuals identifying themselves as representatives or officials of organizations or businesses, available for public inspection in their entirety.

2. Summary Cost and Royalty Impact Data

Summarized below are the estimated costs and benefits of the proposed rule to all potentially affected groups: Industry, the Federal Government, and State and local governments. The costs and the royalty collection impacts, are segregated into two categories—those that would accrue in the first year after the proposed rule becomes effective and those that would accrue on a continuing basis each year thereafter. Of the five proposed changes that have cost impacts, four will result in royalty decreases for industry, States, and MMS. One change will result in a royalty increase. The net impact of the five changes will result in an expected overall royalty decrease of $6,916,000, as itemized below.

A. Industry

(1) Net decrease in royalties—Allowable transportation deduction for unused firm demand charges. Under this proposed rule, industry would be allowed to deduct the portion of firm demand charges it paid “arm's-length” to a pipeline, but did not use. Currently, industry may deduct only the firm demand rate per MMBtu applied to the actual volume transported. Therefore, calculating the estimated royalty decrease would be accomplished by determining the total firm demand charges paid to a pipeline and then determining the portion of capacity that is unused. For example, if the lessee ships only 80 percent of the firm capacity it paid for, then it would be able to deduct an additional 20 percent of the total firm demand charges paid. For estimating the annual royalty decrease of this provision of the proposed rule, the following data and assumptions are used:

The total transportation allowances deducted by Federal lessees from gas royalties for FY 2002 were approximately $103,789,000. While MMS does not maintain data or request information regarding the percentage of transportation allowances that fall under either the arm's-length or non-arm's-length category, we believe that gas, unlike oil, is typically transported through interstate pipelines not owned by the lessee. Therefore, we estimate that 75 percent of all gas transportation allowances are arm's-length. We also made the following two assumptions: (1) On average, firm demand charges account for less than 20 percent of arm's-length transportation payments made by Federal lessees to transport gas away from the lease to a sales point (because of their steep cost and level of service, firm demand charges are predominantly paid to pipelines by local distribution companies to guarantee delivery of gas to retail customers), and (2) the amount of unused capacity is 25 percent (although capacity utilization can vary widely from pipe to pipe and from time to time, minimum volumes of gas flowing through an interstate pipeline are typically around 75 percent of the total pipeline capacity). Using these parameters as a maximum estimate of the revenue impact, the royalty decrease for industry resulting from deducting unused firm demand charges would be at most $3,892,000 ($103,789,000 × 0.75 × 0.2 × 0.25).

(2) Net decrease in royalties—Increase Rate of Return in non-arm's-length situations from 1 times the Standard and Poor's BBB bond rate to 1.3 times the Standard and Poor's BBB bond rate. Based on the above estimate of arm's-length transportation usage, we assumed that 25 percent of all reported gas transportation allowances are non-arm's-length. We also assumed that over the life of the pipeline, allowance rates are made up of 1/3 rate of return on undepreciated capital investment, 1/3 depreciation expenses and 1/3 operation, maintenance and overhead expenses (these are the same assumptions used in the recent threshold analysis for the Federal oil valuation rulemaking). Based on total gas transportation allowance deductions of $103,789,000 for FY 2002, and our assumptions regarding the makeup of the allowance components, the portion of allowances attributable to the rate of return would be approximately $8,649,000. Therefore, we estimated that increasing the basis for the rate of return by 30 percent could result in additional allowance deductions of $2,594,725 ($8,649,000 × .30). That is, the net decrease in royalties paid by industry would be approximately $2,595,000.

(3a) Net decrease in royalties—Allow Line Loss as a component of a non-arm's-length transportation allowance. For this analysis, we assumed that gas pipeline losses are 0.2 percent of the volume transported through the pipeline, which would also equate to 0.2 percent of the value of the Federal royalty share of gas production transported. For FY 2002, the total value of the Federal gas royalty share subject to transportation allowances was approximately $2,506,447,000. Assuming 25 percent of that amount was associated with non-arm's-length transportation, the value of the line loss would be $1,253,224 ($2,506,447,000 × .25 × .002). Therefore, the net decrease in royalties would be approximately $1,253,000 annually.

(3b) Net decrease in royalties—Allow the cost of a Letter of Credit as a component of an arm's-length transportation allowance. The cost of a letter of credit is based on the volume of gas transported through a pipeline under third-party transportation. Therefore, in estimating the annual royalty impact of this provision, we first estimated the total volume of the FY 2002 Federal gas royalty share that would be subject to a transportation allowance. We estimated that volume would be no more than 80 percent of the total Federal gas royalty share onshore and offshore. We also estimated that, based on the total sales volume of gas from Federal onshore and offshore leases (5,821,978,000 Mcf) and the average onshore and offshore royalty rate of 13.55 percent, the royalty share of Federal gas production subject to a transportation allowance would be approximately 631,000,000 Mcf. Next, we assumed that 75 percent of that volume would be transported at arm's length, and that typical letter of credit costs would be at most $0.03 per Mcf for 2 months (or 1/6 of a year) supply of gas transported. Finally, we assumed that only 20 percent of those shippers (by volume) did not meet the pipeline credit standards and were required to post a letter of credit, because most Federal gas is transported by major oil corporations with A or higher credit ratings. We thus estimated that the additional cost to industry for which an allowance deduction could be taken against royalties would be no more than approximately $473,000 per year (631,000,000 × .75 × .2 × 1/6 × $0.03).

(4) Net increase in royalties—Require computation under the exception to use non-arm's-length transportation costs to be based on actual arm's-length charges instead of the FERC tariff rate. Our database for requests to use a FERC-approved tariff as an exception to non-arm's-length transportation costs indicates that MMS has received 94 such requests dating back to 1990 (When approved, these exceptions would continue year after year). Therefore, it is apparent that use of the exception is widespread under non-arm's-length transportation situations. Therefore, for this revenue impact analysis, we assumed that at least 50 percent of the non-arm's-length allowances are based on a FERC tariff. (We are not aware of any State-approved tariffs being used). Because we do not have any data suggesting what the average FERC tariff rate would be nationwide, due to significantly varying market conditions, locational differences, and myriad tariff structures, we must assume a conservative estimate regarding the percentage discount to the tariff that would be negotiated by arm's-length shippers. We believe, on average, a reasonable discount that would be paid under the FERC tariff would be 90 percent of the full tariff rate. Therefore, under the new proposed provision, lessees would be allowed to deduct only 90 percent of the tariff rate, instead of 100 percent, a 10 percent reduction in the reported allowance amount. Using these assumptions (including the assumption that 25 percent of reported transportation allowances are non-arm's-length), we estimate that royalties will therefore increase by about $1,297,000 per year ($103,789,000 × .25 × .5 × .1 = $1,297,000).

B. State and Local Governments

This rule will not impose any additional burden on local governments. The MMS estimates that States impacted by this rule would receive an overall decrease in royalties as indicated below:

States receiving revenues from offshore Outer Continental Shelf Lands Act Section 8(g) leases would share in a portion of the reduced royalties resulting from additional transportation allowance deductions claimed by industry. Based on the ratio of offshore Federal revenues disbursed to States for section 8(g) leases (.61 percent), it is assumed that the same proportion of allowance deductions for offshore transportation would impact those State revenues. Of the $103,789,000 total gas transportation allowance deductions for FY 2002, $52,363,000 (or about 50.5 percent) was attributable to offshore production. Using the total revenue impacts calculated under A.(1), (2), (3a), (3b), and (4) above ($6,916,000) applied to offshore production using the offshore factor of 50.5 percent, and the disbursement percentage attributable to section 8(g) leases from Federal offshore revenues of .61 percent, the net offshore impact on State revenues for 8(g) lease would be approximately $21,000 (($6,916,000 × .505 × 0.0061 = $21,000). Using the factor of .0030805 (.505 × .0061) applied to the royalty decrease or increase, the impact of each proposed change described above can be easily computed for the States:

(1) Net decrease in royalties—Allowable transportation deduction for unused firm demand charges. $3,892,000 × .0030805 = $11,989.

(2) Net decrease in royalties—Increase Rate of Return in non-arm's-length situations from 1 times the Standard and Poor's BBB bond rate to 1.3 times the Standard and Poor's BBB bond rate. $2,595,000 × .0030805 = $7,994.

(3a) Net decrease in royalties—Allow Line Loss as a component of a non-arm's-length transportation allowance. $1,253,000 × .0030805 = $3,860.

(3b) Net decrease in royalties—Allow the cost of a Letter of Credit as a component of an arm's-length transportation allowance. $473,000 × .0030805 = $1,457.

(4) Net increase in royalties—Require computation under the exception to use non-arm's-length transportation costs to be based on actual arm's-length charges instead of the FERC tariff rate. $1,297,000 × .0030805 = $3,995.

For States receiving 50 percent of the revenues from onshore Federal lands (onshore transportation allowances account for 49.5 percent of the total gas transportation allowance deductions for FY 2002), the estimated net onshore impact would be approximately $1,712,000 ($6,916,000 × .495 × .5 = $1,712,000). Using the factor of .2475 (.495 × .5) applied to the royalty decrease or increase, the impact of each proposed change described above can be easily computed for the States:

(1) Net decrease in royalties—Allowable transportation deduction for unused firm demand charges. $3,892,000 × .2475 = $963,270.

(2) Net decrease in royalties—Increase Rate of Return in non-arm's-length situations from 1 times the Standard and Poor's BBB bond rate to 1.3 times the Standard and Poor's BBB bond rate. $2,595,000 × .2475 = $642,263.

(3a) Net decrease in royalties—Allow Line Loss as a component of a non-arm's-length transportation allowance. $1,253,000 × .2475 = $310,118.

(3b) Net decrease in royalties—Allow the cost of a Letter of Credit as a component of an arm's-length transportation allowance. $473,000 × .2475 = $117,067.

(4) Net increase in royalties—Require computation under the exception to use non-arm's-length transportation costs to be based on actual arm's-length charges instead of the FERC tariff rate. $1,297,000 × .2475 = $321,007.

The total impact on all States from offshore and onshore production would be $1,733,000, representing the net impact of the royalty decreases and the royalty increase from offshore and onshore. For each proposed change, the total impact on the States would be the sum of the 8(g) impacts plus the onshore impacts itemized above:

(1) Net decrease in royalties—Allowable transportation deduction for unused firm demand charges. $11,989 + $963,270 = $975,259.

(2) Net decrease in royalties—Increase Rate of Return in non-arm's-length situations from 1 times the Standard and Poor's BBB bond rate to 1.3 times the Standard and Poor's BBB bond rate. $7,994 + 642,263 = $650,257.

(3a) Net decrease in royalties—Allow Line Loss as a component of a non-arm's-length transportation allowance. $3,860 + $310,118 = $313,978.

(3b) Net decrease in royalties—Allow the cost of a Letter of Credit as a component of an arm's-length transportation allowance. $1,457 + 117,067 = $118,5.

(4) Net increase in royalties—Require computation under the exception to use non-arm's-length transportation costs to be based on actual arm's-length charges instead of the FERC tariff rate. $3,995 + $321,007 = $325,002.

C. Federal Government

The Federal Government, like the States, would be impacted by a net overall decrease in royalties as a result of the proposed changes to the regulations governing transportation allowance computations. In fact, the royalty decrease experienced by the Federal Government would be the difference between the total royalty decrease benefiting industry and the royalty decrease affecting the States. In other words, the royalty savings by industry would be shared proportionately between the States and the Federal Government as computed below. The net impact on the Federal Government would be approximately $5,183,000.

(1) Net decrease in royalties—Allowable transportation deduction for unused firm demand charges. $3,892,000 − $975,259 = $2,916,741.

(2) Net decrease in royalties—Increase Rate of Return in non-arm's-length situations from 1 times the Standard and Poor's BBB bond rate to 1.3 times the Standard and Poor's BBB bond rate. $2,595,000 − $650,257 = $1,944,743.

(3a) Net decrease in royalties—Allow Line Loss as a component of a non-arm's-length transportation allowance. $1,253,000 − $313,978 = $939,022.

(3b) Net decrease in royalties—Allow the cost of a Letter of Credit as a component of an arm's-length transportation allowance. $473,000 − $118,524 = $354,476.

(4) Net increase in royalties—Require computation under the exception to use non-arm's-length transportation costs to be based on actual arm's-length charges instead of the FERC tariff rate. $1,297,000 − $325,002 = $971,998.

D. Summary of Costs and Benefits to Industry, State and Local Governments, and the Federal Government

In the table, a negative number means a reduction in payment or receipt of royalties or a reduction in costs. A positive number means an increase in payment or receipt of royalties or an increase in costs. The net expected change in royalty impact is the sum of the royalty increases and decreases.

Summary of Costs and Royalty Impacts

Description	Costs and royalty increases or royalty decreases
	Fiscal year	Subsequent years
A. Industry
(1) Royalty Decrease—Allowable transportation deductions	−$8,213,000	−$8,213,000
(2) Royalty Increase—Restricted use of FERC tariff charges	1,297,000	1,297,000
(3) Net Expected Change in Royalty Payments from Industry	−6,916,000	−6,916,000
B. State and Local Governments
(1) Royalty Decrease—Allowable transportation deductions	−2,058,000	−2,058,000
(2) Royalty Increase—Restricted use of FERC tariff charges	325,000	325,000
(3) Net Expected Change in Royalty Payments to States	−1,733,000	−1,733,000
C. Federal Government
(1) Royalty Decrease—Allowable transportation deductions	−6,155,000	−6,155,000
(2) Royalty Increase—Restricted use of FERC tariff charges	972,000	972,000
(3) Net Expected Change in Royalty Payments to Federal Government	−5,183,000	−5,183,000

3. Regulatory Planning and Review, Executive Order 12866

Under the criteria in Executive Order 12866, this proposed rule is not an economically significant regulatory action as it does not exceed the $100 million threshold. The Office of Management and Budget (OMB) has made the determination under Executive Order 12866 to review this proposed rule because it raises novel legal or policy issues.

1. This proposed rule will not have an annual effect of $100 million or adversely affect an economic sector, productivity, jobs, the environment, or other units of Government. The MMS has evaluated the costs of this rule, and has determined that it will impose no additional administrative costs.

2. This proposed rule will not create inconsistencies with other agencies' actions.

3. This proposed rule will not materially affect entitlements, grants, user fees, loan programs, or the rights and obligations of their recipients.

4. This proposed rule will raise novel legal or policy issues. See Explanation of Proposed Amendments in the Preamble of this proposed rule.

4. Regulatory Flexibility Act

I certify that this proposed rule will not have a significant economic effect on a substantial number of small entities as defined under the Regulatory Flexibility Act (5 U.S.C. 601 et seq.). An initial Regulatory Flexibility Analysis is not required. Accordingly, a Small Entity Compliance Guide is not required. See the above Analysis titled “Summary of Costs and Royalty Impacts.”

Your comments are important. The Small Business and Agricultural Regulatory Enforcement Ombudsman and 10 Regional Fairness Boards were established to receive comments from small businesses about Federal agency enforcement actions. The Ombudsman will annually evaluate the enforcement activities and rate each agency's responsiveness to small business. If you wish to comment on the enforcement actions in this rule, call 1-800-734-3247. You may comment to the Small Business Administration without fear of retaliation. Disciplinary action for retaliation by an MMS employee may include suspension or termination from employment with the Department of the Interior.

5. Small Business Regulatory Enforcement Act (SBREFA)

This proposed rule is not a major rule under 5 U.S.C. 804(2), the Small Business Regulatory Enforcement Fairness Act. This proposed rule:

1. Does not have an annual effect on the economy of $100 million or more. See the Analysis titled “Summary of Costs and Royalty Impacts.”

2. Will not cause a major increase in costs or prices for consumers, individual industries, Federal, State, or local government agencies, or geographic regions.

3. Does not have significant adverse effects on competition, employment, investment, productivity, innovation, or the ability of U.S.-based enterprises to compete with foreign-based enterprises.

6. Unfunded Mandates Reform Act

In accordance with the Unfunded Mandates Reform Act (2 U.S.C. 1501 et seq.):

1. This proposed rule will not significantly or uniquely affect small governments. Therefore, a Small Government Agency Plan is not required.

2. This proposed rule will not produce a Federal mandate of $100 million or greater in any year; i.e., it is not a significant regulatory action under the Unfunded Mandates Reform Act. The analysis prepared for Executive Order 12866 will meet the requirements of the Unfunded Mandates Reform Act. See the above Analysis titled “Summary of Costs and Royalty Impacts.”

7. Governmental Actions and Interference With Constitutionally Protected Property Rights (Takings), Executive Order 12630

In accordance with Executive Order 12630, this proposed rule does not have significant takings implications. A takings implication assessment is not required.

8. Federalism, Executive Order 13132

In accordance with Executive Order 13132, this proposed rule does not have federalism implications. A federalism assessment is not required. It will not substantially and directly affect the relationship between the Federal and State governments. The management of Federal leases is the responsibility of the Secretary of the Interior. Royalties collected from Federal leases are shared with State governments on a percentage basis as prescribed by law. This proposed rule would not alter any lease management or royalty sharing provisions. It would determine the value of production for royalty computation purposes only. This proposed rule would not impose costs on States or localities.

9. Civil Justice Reform, Executive Order 12988

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

10. Paperwork Reduction Act of 1995

This proposed rulemaking does not contain new information collections requirements nor significantly change existing information collection requirements; therefore, a submission to OMB is not required. The information collection requirements referenced in this proposed rule are currently approved by OMB under OMB control number 1010-0140 (OMB approval expires October 31, 2006). The total hour burden currently approved under 1010-0140 is 125,856 hours. We request comments on whether there is an increased burden on the industry compared to the current rule from proposed §206.157 (b)(5) that would require lessees to calculate a transportation allowance based on the volume-weighted average of the rates paid by the third parties under arm's-length transportation contracts.

11. National Environmental Policy Act

This proposed rule deals with financial matters and has no direct effect on MMS decisions on environmental activities. Pursuant to 516 DM 2.3A (2), section 1.10 of 516 DM 2, Appendix 1 excludes from documentation in an environmental assessment or impact statement “policies, directives, regulations and guidelines of an administrative, financial, legal, technical or procedural nature; or the environmental effects of which are too broad, speculative or conjectural to lend themselves to meaningful analysis and will be subject later to the NEPA process, either collectively or case-by-case.” Section 1.3 of the same appendix clarifies that royalties and audits are considered to be routine financial transactions that are subject to categorical exclusion from the NEPA process.

12. Government-to-Government Relationship With Tribes

In accordance with the President's memorandum of April 29, 1994, “Government-to-Government Relations with Native American Tribal Governments” (59 FR at 22951) and 512 DM 2, we have evaluated potential effects on federally recognized Indian tribes and have determined that the changes we are proposing for Federal leases will not have an impact on Indian leases.

13. Effects on the Nation's Energy Supply, Executive Order 13211

In accordance with Executive Order 13211, this regulation does not have a significant adverse effect on the nation's energy supply, distribution, or use. The proposed changes better reflect the way industry accounts internally for its gas valuation and provides a number of technical clarifications. None of these changes should impact significantly the way industry does business, and accordingly should not affect their approach to energy development or marketing. Nor does the proposed rule otherwise impact energy supply, distribution, or use.

14. Consultation and Coordination With Indian Tribal Governments, Executive Order 13175

In accordance with Executive Order 13175, this proposed rule does not have tribal implications that impose substantial direct compliance costs on Indian tribal governments.

15. Clarity of This Regulation

Executive Order 12866 requires each agency to write regulations that are easy to understand. We invite your comments on how to make this rule easier to understand, including answers to questions such as the following: (1) Are the requirements in the rule clearly stated? (2) Does the rule contain technical language or jargon that interferes with its clarity? (3) Does the format of the rule (grouping and order of sections, use of headings, paragraphing, etc.) aid or reduce its clarity? (4) Would the rule be easier to understand if it were divided into more (but shorter) sections? (A “section” appears in bold type and is preceded by the symbol § and a numbered heading; for example, § 204.200 What is the purpose of this part?) (5) Is the description of the rule in the Supplementary Information section of the preamble helpful in understanding the proposed rule? What else could we do to make the rule easier to understand? Send a copy of any comments that concern how we could make this rule easier to understand to: Office of Regulatory Affairs, Department of the Interior, Room 7229, 1849 C Street, NW., Washington, DC 20240. You may also e-mail the comments to this address: [e-mail].

List of Subjects in 30 CFR Part 206

• Continental shelf
• Government contracts
• Mineral royalties
• Natural gas
• Petroleum
• Public lands—mineral resources

Dated: April 28, 2004.

Patricia Morrison,

Acting Assistant Secretary for Land and Minerals Management.

For the reasons set forth in the preamble, part 206 of title 30 of the Code of Federal Regulations is proposed to be amended as follows:

PART 206—PRODUCT VALUATION

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

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

2. In § 206.150, paragraph (b) is revised as follows:

§ 206.150

Purpose and scope.

* * * * *

(b) If the regulations in this subpart are inconsistent with:

(1) A Federal statute;

(2) A settlement agreement between the United States and a lessee resulting from administrative or judicial litigation;

(3) A written agreement between the lessee and the MMS Director establishing a method to determine the value of production from any lease that MMS expects at least would approximate the value established under this subpart; or

(4) An express provision of an oil and gas lease subject to this subpart, then the statute, settlement agreement, written agreement, or lease provision will govern to the extent of the inconsistency.

* * * * *

3. In § 206.151, a new definition of “affiliate” is added in alphabetical order and the definitions of “allowance” and “arm's-length contract” are revised to read as follows:

§ 206.151

Definitions.

* * * * *

Affiliate means a person who controls, is controlled by, or is under common control with another person. For purposes of this subpart:

(1) Ownership or common ownership of more than 50 percent of the voting securities, or instruments of ownership, or other forms of ownership, of another person constitutes control. Ownership of less than 10 percent constitutes a presumption of noncontrol that MMS may rebut.

(2) If there is ownership or common ownership of between 10 and 50 percent of the voting securities or instruments of ownership, or other forms of ownership, of another person, MMS will consider the following factors in determining whether there is control under the circumstances of a particular case:

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

(ii) With respect to the voting securities, or instruments of ownership, or other forms of ownership: the percentage of ownership or common ownership, the relative percentage of ownership or common ownership compared to the percentage(s) of ownership by other persons, whether a person is the greatest single owner, or whether there is an opposing voting bloc of greater ownership;

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

(iv) The extent of participation by other owners in operations and day-to-day management of a lease, plant, pipeline, or other facility; and

(v) Other evidence of power to exercise control over or common control with another person.

(3) Regardless of any percentage of ownership or common ownership, relatives, either by blood or marriage, are affiliates.

Allowance means a deduction in determining value for royalty purposes. Processing allowance means an allowance for the reasonable, actual costs of processing gas determined under this subpart. Transportation allowance means an allowance for the reasonable, actual costs of moving unprocessed gas, residue gas, or gas plant products to a point of sale or delivery off the lease, unit area, or communitized area, or away from a processing plant. The transportation allowance does not include gathering costs.

* * * * *

Arm's-length contract means a contract or agreement between independent persons who are not affiliates and who have opposing economic interests regarding that contract. To be considered arm's length for any production month, a contract must satisfy this definition for that month, as well as when the contract was executed.

* * * * *

4. Section 206.157 is amended as follows:

A. Paragraph (b)(2)(v) is revised;

B. Paragraph (b)(5) is revised;

C. Paragraph (c) is revised;

D. Paragraphs (f) introductory text, (f)(1), and (f)(7) are revised and paragraph (f)(10) is added; and

E. The word “and” at the end of paragraph (g)(4) is removed, paragraph (g)(5) is revised, and new paragraphs (g)(6) through (g)(8) are added.

The additions and revisions read as follows:

§ 206.157

Determination of transportation allowances.

* * * * *

(b) * * *

(2) * * *

(v) The rate of return must be 1.3 times the industrial rate associated with Standard and Poor's BBB rating. The BBB rate must be the monthly average rate as published in Standard and Poor's Bond Guide for the first month for which the allowance is applicable. The rate must be redetermined at the beginning of each subsequent calendar year.

* * * * *

(5) You may apply for an exception from the requirement to compute actual costs under paragraphs (b)(1) through (b)(4) of this section.

(i) The MMS will grant the exception if:

(A) The transportation system has a tariff approved by the Federal Energy Regulatory Commission (FERC) or a State regulatory agency that FERC or the State regulatory agency has either adjudicated or specifically analyzed, and

(B) Third parties are paying prices under the tariff to transport gas on the system under arm's-length transportation contracts.

(ii) If MMS approves the exception, you must calculate your transportation allowance for each production month based on the volume-weighted average of the rates paid by the third parties under arm's-length transportation contracts during that production month. If during any production month there are no prices paid under the tariff by third parties to transport gas on the system under arm's-length transportation contracts, you may use the volume-weighted average of the rates paid by third parties under arm's-length transportation contracts in the most recent preceding production month in which third parties paid such rates, for up to two successive production months.

(iii) You may use the exception under this paragraph if the tariff remains in effect and no more than two production months have elapsed since third parties paid prices under the tariff to transport gas on the system under arm's-length transportation contracts.

(c) Reporting requirements—(1) Arm's-length contracts. (i) You must use a separate entry on Form MMS-2014 to notify MMS of a transportation allowance.

(ii) The MMS may require you to submit arm's-length transportation contracts, production agreements, operating agreements, and related documents. Recordkeeping requirements are found at part 207 of this chapter.

(iii) You may not use a transportation allowance that was in effect before March 1, 1988. You must use the provisions of this subpart to determine your transportation allowance.

(2) Non-arm's-length or no contract. (i) You must use a separate entry on Form MMS-2014 to notify MMS of a transportation allowance.

(ii) For new transportation facilities or arrangements, base your initial deduction on estimates of allowable gas transportation costs for the applicable period. Use the most recently available operations data for the transportation system or, if such data are not available, use estimates based on data for similar transportation systems. Paragraph (e) of this section will apply when you amend your report based on your actual costs.

(iii) The MMS may require you to submit all data used to calculate the allowance deduction. Recordkeeping requirements are found at part 207 of this chapter.

(iv) If you are authorized under paragraph (b)(5) of this section to use an exception to the requirement to calculate your actual transportation costs, you must follow the reporting requirements of paragraph (c)(1) of this section.

(v) You may not use a transportation allowance that was in effect before March 1, 1988. You must use the provisions of this subpart to determine your transportation allowance.

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(f) Allowable costs in determining transportation allowances. You may include, but are not limited to (subject to the requirements of paragraph (g) of this section), the following costs in determining the arm's-length transportation allowance under paragraph (a) of this section or the non-arm's-length transportation allowance under paragraph (b) of this section. You may not use any cost as a deduction that duplicates all or part of any other cost that you use under this paragraph.

(1) Firm demand charges paid to pipelines. You may deduct firm demand charges or capacity reservation fees paid to a pipeline, including charges or fees for unused firm capacity that you have not sold before you report your allowance. If you receive a payment from any party for release or sale of firm capacity after reporting a transportation allowance that included the cost of that unused firm capacity, or if you receive a payment or credit from the pipeline for penalty refunds, rate case refunds, or other reasons, you must reduce the firm demand charge claimed on the Form MMS-2014 by the amount of that payment. You must modify the Form MMS-2014 by the amount received or credited for the affected reporting period, and pay any resulting royalty and late payment interest due;

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(7) Payments (either volumetric or in value) for actual or theoretical losses. However, theoretical losses are not deductible in non-arm's-length transportation arrangements unless the transportation allowance is based on arm's-length transportation rates charged under a FERC-or State regulatory-approved tariff under paragraph (b)(5) of this section. If you receive volumes or credit for line gain, you must reduce your transportation allowance accordingly and pay any resulting royalties and late payment interest due.

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(10) Costs of surety. You may deduct the costs of securing a letter of credit, or other surety, that the pipeline requires you as a shipper to maintain under an arm's-length transportation contract.

(g) * * *

(5) Fees paid to brokers. This includes fees paid to parties who arrange marketing or transportation, if such fees are separately identified from aggregator/marketer fees;

(6) Fees paid to scheduling service providers. This includes fees paid to parties who provide scheduling services, if such fees are separately identified from aggregator/marketer fees;

(7) Internal costs. This includes salaries and related costs, rent/space costs, office equipment costs, legal fees, and other costs to schedule, nominate, and account for sale or movement of production; and

(8) Other nonallowable costs. Any cost you incur for services you are required to provide at no cost to the lessor.

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Footnotes

2.  IPAA challenges that principle at pp. 41-43 of its original brief, but the Court's Opinion contains no discussion of this issue. Defendants thus infer that the Court did not mean to invalidate this provision of the cited paragraphs.