05-4515. Federal Gas Valuation

AGENCY:

Minerals Management Service (MMS), Interior.

ACTION:

Final rule.

SUMMARY:

The MMS is amending the existing regulations governing the valuation of gas produced from Federal leases for royalty purposes, and related provisions governing the reporting thereof. The current regulations became effective on March 1, 1988, and were amended in 1996 and 1998. These amendments primarily affect the calculation of transportation deductions and the changes necessitated by judicial decisions since the regulations were last amended.

DATES:

Effective date: June 1, 2005.

FOR FURTHER INFORMATION CONTACT:

Sharron L. Gebhardt, Lead Regulatory Specialist, Chief of Staff Office, 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, Larry E. Cobb, Susan Lupinski, Mary A. Williams, and Kenneth R. Vogel of Minerals Revenue Management, MMS, Department of the Interior.

SUPPLEMENTARY INFORMATION:

I. Background

The MMS is amending the existing regulations at 30 CFR 206.150 et seq., governing the valuation of gas produced from Federal leases for royalty purposes, and related provisions governing the reporting thereof. The current regulations became effective on March 1, 1988 (53 FR 1230) (1988 Gas Rule).

After conducting several public workshops, MMS issued a proposed rule that was published in the Federal Register on July 23, 2004 (69 FR 43944). The comment period for the proposed rule closed on September 21, 2004.

The amendments do not alter the basic structure or underlying principles of the 1988 Gas Rule.

II. Comments on the Proposed Rule

Comments received favored most of the proposed changes. The MMS received some unfavorable comments regarding future valuation agreements between the MMS Director and the lessee, some of the specifications of allowable transportation costs, and our proposal to change the rate of return on undepreciated capital investment in calculating non-arm's-length transportation allowances. Generally, we grouped the comments received and the MMS responses according to the order of the issues and proposed revisions on which we requested comments. We also addressed miscellaneous technical changes.

A. Spot Market Prices

In the proposed rule, we requested comments on (1) “whether publicly available spot market prices for natural gas are reliable and representative of market value” and whether MMS should value natural gas production that is not sold at arm's-length using spot market prices and, if so, (2) “how these spot market prices should be adjusted for location differences between the index pricing point and the lease.”

Summary of Comments: One producer supported using index pricing, stating that index pricing provides the most accurate and transparent gas pricing information available and, therefore, increases royalty valuation certainty.

Industry trade associations supported the use of index pricing for gas valuation and questioned why index pricing does not apply to arm's-length gas sales.

One state and the State and Tribal Royalty Audit Committee (STRAC) did not support using index pricing to value gas. The state claimed that publicly available spot prices are not a true representation of arm's-length market value because non-arm's-length sales are included within the index. The state proposed that MMS publish a new gas rule requiring a Federal lessee to value natural gas and associated products based on the first arm's-length sale of the gas or products.

MMS Response: The written comments received continue to reflect disparate and conflicting views of industry and states. At the present time, MMS has decided not to change existing regulations for valuing production that is not sold at arm's-length and will continue to evaluate the issues.

B. Section 206.150—Purpose and Scope

The MMS proposed to amend the Federal gas valuation rule to match the June 2000 Federal oil valuation rule, which provides that, if a written agreement between a 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. The MMS used this provision in the June 2000 Federal oil valuation rule to address unexpectedly difficult royalty valuation problems.

Summary of Comments: Industry producers and industry trade associations support this change.

Two states and STRAC do not support the use of written valuation agreements. One state commented that it is not in the public's best interest to allow the MMS Director to avoid the regulations that are subject to notice and comment. The states claimed that, at the very minimum, state approval should be necessary if this provision is implemented. STRAC commented that the provision is not clear and that state approval should be required if state royalties are affected.

MMS Response: The MMS is mindful of the states' concerns, but does not believe that written valuation agreements should be subject to state approval (or veto). Such agreements are not an avenue to avoid the rules, but rather a tool to provide certainty and reduce administrative costs in appropriate circumstances. The rule requires that value under such an agreement at least approximate the value that would be derived under the regulations. Therefore, these agreements should not result in significant revenue consequences to the Federal Government or to the states.

C. Section 206.151—Definitions

The MMS proposed adding a definition of “affiliate” and revising the definition of “arm's-length contract” to be identical to the June 2000 Federal oil valuation rule, as amended, and to conform the Federal gas valuation rule with the DC Circuit holding of National Mining Association v. Department of the Interior, 177 F.3d 1 (DC Cir. 1999). The MMS proposed revising the definition of “affiliate” separately from the definition of “arm's-length contract” as in the June 2000 Federal oil valuation rule, as amended, to clarify and simplify the definitions.

The MMS also proposed to revise the definition of “transportation allowance” to be consistent with the June 2000 Federal oil valuation rule with necessary changes in wording to apply it in the gas context. Finally, MMS proposed to revise the definition of “processing allowance” to make it consistent with other allowance definitions.

Summary of Comments: Industry producers and industry trade associations supported the addition of “affiliate” but requested further clarification of the term “opposing economic interests” used in the definition of “affiliate.” One trade association urged MMS to adopt a presumption of opposing economic interests where common ownership is less than the 50 percent threshold in the definition of “affiliate” for transportation and processing affiliates. One state also supported the proposed change to “affiliate.”

One state supported the definition of “transportation allowance,” but not “to the extent it could be applied inconsistent [sic] with the marketability rule, such as providing for an allowance for the movement of unprocessed gas to a point of delivery off-lease, if that point of delivery is a gas plant or gas treating facility.” One industry trade association recommended that the adoption of the revision be prospective only.

No comments were received on the definition of “processing allowance.”

One state and STRAC suggested that the “marketing affiliate” definition should be removed from the regulations. Another state requested that the word “only” be replaced with “any of” in the definition of “marketing affiliate” to require valuation based on downstream re-sales. One industry producer requested that MMS revise the definition of “gathering,” stating that disallowing gathering costs is overly restrictive. One industry trade association requested a better definition of “line loss.”

MMS Response: In addition to the fact that the proposed gas rule did not include a discussion of the meaning of “opposing economic interests,” the question of whether two parties have opposing economic interests depends on the facts of a particular situation. The MMS does not believe that opposing economic interests should be presumed simply because there may be less than 50 percent common ownership between two entities.

The MMS has modified the wording of the second paragraph of the proposed definition of “affiliate” to change the phrase “between 10 and 50 percent” ownership or common ownership to “10 through 50 percent” to be consistent with the June 2000 Federal oil valuation rule, as amended.

Contrary to the comment by one state commenter, the definition of “transportation allowance” is not inconsistent with the marketable condition rule. The commenter's view that there should be no transportation allowance for the movement of unprocessed gas to an off-lease delivery point if that point is a gas plant is contrary to 30 CFR 206.156(a), which allows a deduction for the reasonable actual costs incurred by the lessee to transport gas * * * from a lease to a point off the lease, including, if appropriate, transportation from the lease to a gas processing plant off the lease * * *.” The state's comment reflects a view that the relationship between transportation allowances and the marketable condition rule should be fundamentally changed. That suggestion is beyond the scope of the proposal. The proposed change to the definition of “transportation allowance,” as explained in the preamble to the proposed rule (69 FR 43946), was to make its wording consistent with the June 2000 Federal crude oil valuation rule and return it to being substantively the same as the original 1988 rule's definition, with the objective of correcting an inadvertent error that the 1996 amendment put into the wording. That change is adopted in the final rule.

The change to the wording of the definition of “transportation allowance” is prospective. However, it reflects how the rule has been applied in practice since the 1988 Gas Rule, even after the 1996 amendment to that rule.

The suggestion to eliminate the definition of “marketing affiliate,” and the suggestion to change the wording of that definition, are beyond the scope of the proposed gas rule. The suggestion of the industry commenter that gathering costs be deductible and the recommendation to provide a more detailed definition of line loss also are beyond the scope of the proposed gas rule.

D. Section 206.157 Determination of Transportation Allowances Rate of Return Used in Non-Arm's-Length Cost Calculations

The MMS proposed an amendment to § 206.157(b)(2)(v) governing calculation of actual transportation costs in non-arm's-length situations by changing the allowed rate of return on (1) undepreciated capital investment or (2) initial investment from 1.0 times the Standard & Poor's BBB bond rate to 1.3 times the Standard & Poor's BBB bond rate.

Summary of Comments: Industry producers and one industry trade association supported the change but asserted that 1.3 times the Standard & Poor's BBB bond rate understates the cost of capital for gas pipelines. Based on a study from the American Petroleum Institute (API), industry argued that, although pipelines are not as risky as drilling wells, some risk is involved, and that the allowable rate of return should be between 1.6 and 1.8 times the Standard & Poor's BBB bond rate.

The states and STRAC opposed the change. One state argued that the rate of return is a profit element and requested that MMS apply the rate of return only to non-arm's-length transportation arrangements for Federal offshore production if the change is implemented. STRAC also suggested that the proposed rate of return apply only to offshore production.

Another state and STRAC asserted that interest rates have hit all time lows and there is no reason to implement the proposed change. As part of STRAC's comments, an Indian tribe suggested that increasing the rate of return on Federal leases may give companies an argument to increase the rate of return on Indian leases.

The congressional commenter opposed the proposed change, stating that it would allow the weighted average cost of capital as the rate of return for the calculation of gas transportation allowances as requested by the oil and gas industry.

MMS Response: The MMS has examined rates of return in the oil and gas industry and believes that some weighted average rate of return considering both equity and debt is appropriate as an actual market-based cost of capital. An investor will choose to have a mix of debt and equity for many reasons, not the least of which is that companies that choose to finance their investments solely by debt will pay a higher interest rate due to the increased risk on the part of the creditor. Both debt and equity costs are actual costs of capital. The choice of Standard & Poor's BBB bond rate in 1988 was made, at least in part, in recognition of some equity component because the majority of companies with non-arm's-length transportation arrangements have debt costs lower than the Standard & Poor's BBB bond rate.

The MMS continues to believe that establishing a uniform rate of return on which all parties can rely is preferable to the costs, delays, and uncertainty inherent in attempting to analyze appropriate project-specific or company-specific rates of return on investment. The MMS, through its Economics Division, Offshore Minerals Management, has studied several years' worth of data for both non-integrated oil and gas transportation companies and larger oil and gas producers, both integrated and independent, that MMS believes are more likely to invest in gas pipelines.

After a thorough review of the MMS and API studies, and consideration of the comments submitted by states and industry, we believe that the allowance for the rate of return on capital should be 1.3 times the Standard & Poor's BBB bond rate. This rate is the mid-point of the range suggested by the MMS study, which concluded that the range of rates of return appropriate for gas pipelines would be in the range of 1.1 to 1.5 times the Standard & Poor's BBB bond rate. The MMS also believes that, although there are some very high risks involved with certain oil and gas ventures, such as wildcat drilling, the risk associated with building and developing a pipeline to move gas that has already been discovered is much less and of a different nature. Both the MMS study and the data from the Energy Information Administration (EIA) demonstrate that the market also perceives that the risk is lower in the transportation lines of business than in the exploration and production lines of business.

The MMS believes that the study conducted by its Economics Division, Offshore Minerals Management, used the most relevant data for a reasonable period and, therefore, is the best source to decide on the appropriate rate of return.

The MMS does not believe that there is any basis to apply the 1.3 times the Standard & Poor's BBB bond rate of return only to offshore leases. We have no evidence that rates of return for onshore pipelines are significantly different than for offshore pipelines.

The fact that interest rates are currently relatively low is irrelevant. As interest rates rise or fall, the Standard & Poor's BBB bond rate will rise or fall.

The royalty valuation for gas produced from Indian leases is now based on different rules than valuation of gas produced from Federal leases. Gas produced from Indian leases is valued primarily on the basis of index prices, and the rate of return is irrelevant because producers are allowed a 10 percent fixed deduction (with limitations). For gas produced from non-index zones, or from leases for which the tribe has elected not to use index-based valuation, there is a potential effect from changing the rate of return on Federal leases. If MMS proposes changes to the Indian gas valuation rule in the future, it would be appropriate to address the issue in that context.

Finally, MMS has retained the proposed wording of paragraph (b)(2)(v), which is the same as the wording in the current rule except to change the rate of return. The wording of paragraph (b)(2)(v) is not identical to the wording of the equivalent provision in the Federal oil valuation rule, as amended, at 30 CFR 206.111(i)(2). The MMS intends that the two provisions have the same effect, namely, that the rate of return must be re-determined at the beginning of each calendar year.

E. Comments Requested on Changing the Rate of Return for Non-Arm's-Length Processing Cost Calculations

The MMS requested comments on changing the rate of return in § 206.159 (b)(2)(v) for non-arm's-length processing cost calculations to gather more information. The MMS Economics Division, Offshore Minerals Management, study of gas pipeline costs of capital did not study the impact of changing the rate of return for non-arm's-length processing cost calculations.

Summary of Comments: Industry trade associations urged MMS to implement the same rate of return for processing cost calculations based on the fact that the cost of capital to an oil and gas company is the same, irrespective of its use. They stated that 1.3 times Standard & Poor's BBB bond rate is conservative and understates the cost of capital.

One state and STRAC recommended that MMS not change the rate of return for non-arm's-length processing cost calculations. STRAC stated that, if the increase is implemented, MMS should retain the Standard & Poor's BBB bond rate, with no multiplier, for gas produced from onshore leases.

MMS Response: In the preamble of the proposed rule, MMS stated that it “welcomes comments, data, and analysis” on the issue of whether 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 (69 FR 43947). The MMS explained that, if it “obtains sufficient information and data through the comment process to support a change,” it may change the rate of return for non-arm's-length processing cost calculations. Id. While industry suggested applying the 1.3 times the Standard & Poor's BBB bond rate to calculation of non-arm's-length processing allowances, no commenter submitted any information or data that would support changing the current processing allowance rate. Industry did suggest that an industry-wide rate of return should be used. As MMS explained in the discussion of transportation rates of return, MMS believes that it is appropriate to use different rates of return for different industry lines of business. It is clear that the risk in exploration and development is greater than the risks in transportation or processing. The MMS was able to study rates of return in the transportation segment, but the study did not extend to processing rates of return. Therefore, we are not adopting any changes to the rate of return used in calculating processing allowances.

F. Section 206.157(b)(5)—Determination of Transportation Allowances—Alternatives to Actual Cost Calculation

The proposed provision would allow 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 that FERC or the state agency has either adjudicated or specifically analyzed, and third parties are paying prices under the tariff to transport gas under arm's-length transportation contracts.

Summary of Comments: One state, two industry trade associations, and STRAC supported the proposed changes. One industry trade association suggested extending the 2-month production period to 3 or 6 months to avoid frequent switching back and forth between calculating actual costs and using third-party tariff rates. The state commented that, if the exception based on the weighted average of rates paid by third parties is used, it be limited to the rates used for “like quantities” (presumably meaning quantities similar to those transported under the non-arm's-length arrangement).

One industry association commented that the addition of the need for the tariff to be adjudicated or specifically analyzed should be clarified or eliminated because it was unclear as to how this requirement would be applied. The association also commented that producers should be allowed to use the exception once it was applied for, without the need for MMS approval.

Two states, one industry trade association, and the congressional commenter opposed the proposed changes. One state commented that MMS does not have the same FERC or state business perspective, and MMS should not move away from basing non-arm's-length transportation charges on actual costs. Another state commented that the use of tariffs for non-arm's-length transportation allowances should be deleted. The industry trade association commented that the current FERC-or state-approved tariffs are fair and reasonable transportation charges and provide certainty to industry and the MMS. The industry trade association also asserted that the proposal is in direct opposition to FERC Order 2004-A.

MMS Response: As MMS explained in 1988, when it first adopted an exception from the requirement to use actual costs in non-arm's-length transportation arrangements, MMS believed that it was reasonable to rely on another regulatory agency with jurisdiction over the prices charged. Since that time, MMS has noted several problems with simply deferring to FERC or state regulatory agencies. First, MMS realized that the requirements for granting an exception under the current rule were burdensome and difficult to apply. Second, MMS now understands that many pipelines grant discounts to their tariffs, and there is no reason for a non-arm's-length shipper to be able to deduct more than the arm's-length shippers can deduct, nor more than its actual payment or transfer price to its affiliated pipeline. Lessees have always been limited to “actual,” as well as “reasonable” costs.

The MMS agrees that it may be difficult for lessees to know when or if a transportation tariff has been “approved” or “adjudicated or specifically analyzed.” Therefore, MMS has changed the language of the exception in the final rule to more closely follow the FERC procedures. The regulation now requires that the tariff be filed and that the FERC or state regulatory agency has permitted the tariff to become effective.

The MMS does agree that limiting the ability to use the exception for 2 months following the last arm's-length transaction may be unduly restrictive. While transportation arrangements normally are stable, MMS believes that it is possible for shippers to stop shipping for as long as a heating season. Heating season sales contracts typically last for 5 months. Therefore, MMS is adjusting the ability of a non-arm's-length shipper to use the exception for 5 months following the last arm's-length transaction. The MMS has also changed the wording of subparagraphs (b)(5)(ii) and (iii) to specify which rate to use in determining a transportation allowance under the exception and to eliminate duplicative language in the proposed rule.

The MMS does not believe it is appropriate for lessees to use this exception without MMS approval. The MMS believes that it needs to know when companies intend to use this exception so that it can monitor which method a company is using, and verify that the tariff has become effective. Under this exception, MMS may retroactively approve an allowance as far back as the date the tariff is filed, so there is no loss to the lessee. Because MMS now pays interest on overpayments, the lessee will not experience a loss of the time value of money.

The MMS does not believe it is practical to try to find arm's-length transportation contracts of “like quantity.” Even though it is likely that the non-arm's-length shippers may ship much larger quantities than the arm's-length shippers, MMS believes that it is reasonable to use the weighted average of all arm's-length contracts. The MMS does not believe that FERC Order 2004-A interferes with the ability of a producer to comply with the requirement to know the prices charged to arm's-length shippers. The Order specifically requires the pipeline to publish all relevant information about each discount given, including rate, execution date, length of contract, quantity scheduled, etc. If a lessee cannot determine the actual volumes shipped under these arm's-length contracts, the lessee may use the published maximum daily quantities as a proxy for actual volumes. Also, the lessee may propose to MMS an alternate method of calculating the weighted average price received by the pipeline affiliate for arm's-length shipments under a tariff for a pipeline segment.

On the other hand, FERC Order 2004-A does seem to make it more difficult for a lessee to know its affiliated pipeline's actual costs unless the pipeline shares that information with the public. The MMS's requirement to use actual costs pre-dates the new FERC information-sharing restrictions and no one either protested the Order on this ground or informed MMS that the Order would interfere with compliance with the Federal gas valuation rule. The MMS does not plan to change the requirement to use actual costs and will work with any lessee that is unable to compute actual costs under the existing regulation. To make clear the ability of a regulated pipeline to share the data necessary for an affiliated lessee to accurately report its transportation deduction, whether it is based on actual costs or on the weighted average of arm's-length transactions, MMS intends to petition the FERC for a declaratory order, which would specify the parameters of the authority of regulated pipelines to share information with MMS and with their affiliated lessee.

G. Section 206.157(c)—Transportation Allowances—Reporting Requirements

The MMS proposed eliminating the requirement to report separate line entries for allowances on the Form MMS-2014 because MMS modified the form in 2001. The MMS also proposed rewording new paragraph (c) to be consistent with the June 2000 Federal oil valuation rule regarding reporting requirements for arm's-length and non-arm's-length transportation contracts, respectively. The MMS further proposed adding new paragraphs (c)(1)(iii) and (c)(2)(v) to expressly clarify that the allowances that were in effect when the 1988 Gas Rule became effective, and that were “grandfathered” under former paragraphs (c)(1)(v) and (c)(2)(v), have been terminated.

Summary of Comments: One industry trade association commented that it supports the proposed changes, although it supports the removal of the “grandfather” clause prospectively. One state and STRAC support removing the “grandfather” clause.

MMS Response: The “grandfather” clause was removed in the 1996 amendment, but subsequent litigation arose regarding whether the removal of the “grandfather” clause was validly accomplished. The amendment made in this final rule eliminates any further question in this regard by clearly ending any grandfathering provision.

H. Section 206.157(f)—Transportation Allowances—Specifying Allowable Costs

MMS proposed to amend section 206.157(f) in several respects to further clarify what costs are deductible in calculating transportation allowances. The proposed changes are listed individually below with specific comments associated with each change.

Summary of Comments: One state commented that unused firm demand charges and costs of surety are indirect costs and should not be deductible. A public interest group and an individual commented that the Government would suffer revenue losses from these changes. These losses would be caused, in their view, by allowing the gas industry to deduct new transportation costs that are not directly related to operating and maintaining a pipeline. STRAC commented that “unused firm capacity/firm demand charges, line loss and cost of surety” are “already paid for under the 7/8ths interest.”

MMS Response: The MMS will respond to these general comments below with respect to each specific provision.

1. Section 206.157(f)(1)—Transportation Allowances—Specifying Allowable Costs—Allow Unused Firm Demand Charges

The MMS proposed to add unused firm demand charges as allowable transportation costs under § 206.157(f)(1) to conform with the DC Circuit's decision in IPAA v. DeWitt, 279 F.3d 1036 (DC Cir. 2002), cert. denied, 537 U.S. 1105 (2003). The proposed rule also provided for reduction of previously reported transportation allowances whenever the lessee sells unused firm capacity after having deducted it as part of a previously reported allowance.

Summary of Comments: Two industry trade associations and one producer supported this change. One state, an individual commenter, a public interest group, and STRAC opposed the change with respect to allowing unused firm demand charges.

MMS Response: As MMS explained in the preamble to the proposed rule, in its 1998 rulemaking, MMS had prohibited the deduction of unused firm demand charges. In IPAA v. DeWitt, while the DC Circuit upheld every other aspect of the 1998 rulemaking, it determined that MMS did not demonstrate that unused demand charges were not transportation. Therefore it held that MMS was required to allow the deduction of unused demand charges. The IPAA sought review of the rest of the case, which was denied, but the government did not seek further review of that decision. The MMS therefore must change the gas rule to conform to the court's decision. The final rule is also intended to be consistent with the Federal oil valuation rule, as amended.

2. Section 206.157(f)(7)—Transportation Allowances—Specifying Allowable Costs—Allow Fees Paid for Actual Line Losses Under Non-Arm's-Length Contracts

The proposed rule specified actual line losses as a cost of moving production. Theoretical line losses would be allowed only in arm's-length transportation situations.

Summary of Comments: Two industry trade associations support the change. Two states and the congressional commenter oppose the proposed change. One state believes that line losses are indirect costs that result from metering differences and are very inaccurate.

MMS Response: The MMS believes that actual line losses properly may be regarded as a cost of moving production. In addition, if there is 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.

3. Section 206.157(f)(10)—Transportation Allowances—Specifying Allowable Costs—Allow the Cost of Securing a Letter of Credit or Other Surety Required by the Pipeline Under Arm's-Length Contracts

The proposed rule would allow the cost of securing a letter of credit or other surety, insofar as those costs are currently allocable to production from Federal leases, in arm's-length transportation situations and are necessary to obtain the pipeline's transportation services.

Summary of Comments: One industry trade association supports the change. Two states, STRAC, and the congressional commenter oppose the proposed change. One state commented that, if MMS allows a cost of surety, it erodes the valuation associated with the Federal Government's royalty interest and “increases the profit margin associated to [sic] the working interest” because this type of cost is a “service fee” that historically has not been deductible. One state and STRAC commented that MMS historically has not allowed service-type fees that are associated with the lessee's responsibility to market the production at no cost to the lessor and that this change should not be allowed.

MMS Response: As explained in the preamble to the proposed rule, 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. The view of state commenters and STRAC that this type of cost is a “service fee” does not address whether incurring the cost is necessary to transport production. Contrary to the view of one state and STRAC, MMS does not believe that the cost of obtaining a letter of credit or other surety is a cost associated with marketing the production. The costs necessary to market the production do not depend on whether a pipeline requires a letter of credit.

As explained in the preamble to the proposed rule, in non-arm's-length situations, MMS believes 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. The MMS therefore believes it is inappropriate to allow such a deduction under non-arm's-length transportation arrangements.

I. Section 206.157(g)—Transportation Allowances—Specifying Non-Allowable Costs (Fees Paid to Brokers, Fees Paid to Scheduling Service Providers, and Internal Costs)

Summary of Comments: Two states and STRAC supported the clarifications. The MMS received no comments opposing these clarifications.

MMS Response: As explained in the preamble to the proposed rule, fees paid to brokers include 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, if such fees are separately identified from aggregator/marketer fees, are marketing or administrative costs that lessees must bear at their own expense and are not actual costs of transportation because, unlike the surety charges, the pipeline does not require that they be paid.

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, have never been deductible. The final rule reaffirms this principle.

J. Other Comments on Allowable or Non-Allowable Costs

Summary of Comments: Two industry trade associations questioned why “line pack” is not an allowable transportation cost. One industry trade association requested that the transportation costs attributable to excess carbon dioxide, where it is necessary to transport the carbon dioxide entrained in the main gas stream before disposal as a waste product, be allowable transportation costs.

MMS Response: With respect to “line pack,” the commenters did not provide any examples in which lessees had actually been charged for line pack as an actual cost of transportation, nor does MMS know of any such situations.

The trade association's comment regarding “excess CO₂” appears to misunderstand the current rule at 30 CFR 206.157(a)(2)(i), which provides that no allowance may be taken for the costs of transporting lease production which is not royalty bearing without MMS approval. The “excess CO₂” removed at a treatment plant is a non-royalty-bearing product. The transportation pipeline will not transport the gas unless the CO₂ is removed. So if the CO₂ is not removed the gas cannot be marketed. The increment of CO₂ allowed in a transportation pipeline (e.g., 2 percent) is a “waste product.” The cost of transporting the “waste product” increment is allowed as part of the cost of transporting gas, while the cost of transporting the non-royalty-bearing product is not. The location at which a lessee chooses to treat production for removal of CO₂ is up to the lessee. If the lessee treats production at a location away from the lease, transporting the excess CO₂ to that location is part of the costs of putting the production into marketable condition and, therefore, is not deductible.

K. Other Comments

Summary of Comments: An industry trade association requested to be able to use the prior year's actual costs in the current year to eliminate reporting of retroactive adjustments on the Form MMS-2014. The association noted that companies must report estimates until actuals are calculated and then reverse previous lines.

MMS Response: This comment and issues related to it are beyond the scope of the proposed rule, and addressing these issues would require initiation of new rulemaking proceedings.

III. Procedural Matters

1. Summary Cost and Royalty Impact Data

Summarized below are the annual estimated costs and royalty impacts of this rule to all potentially affected groups: industry, the Federal Government, and state and local governments. The MMS did not receive any specific comments regarding the estimated costs and royalty impacts of this rule when it was proposed in the Federal Register July 23, 2004 (69 FR 43944). The costs and royalty impact estimates have changed since the proposed rule due to further analysis.

Of the changes being implemented under this rulemaking that have cost impacts, some will result in royalty decreases for industry, states, and MMS, and two changes will result in a royalty increase. The net impact of the changes will result in an expected overall royalty increase of $2,251,000, as itemized below.

A. Industry

(1) No Change in Royalties—Allow Transportation Deduction for Unused Firm Demand Charges.

Under this rule, industry is allowed to deduct the portion of firm demand charges it paid “arm's-length” to a pipeline, but did not use. Currently, following the decision of the DC Circuit in IPAA v. DeWitt, industry may already deduct these charges. In the proposed rule, MMS estimated a revenue decrease from this provision. The MMS now realizes that this provision is merely codifying existing law and no royalty change is effected by this clarification.

(2) Net Decrease in Royalties—Increase Rate of Return in Non-Arm's-Length Situations From 1 Times the Standard & Poor's BBB Bond Rate to 1.3 Times the Standard & Poor's BBB Bond Rate.

The total transportation allowances deducted by Federal lessees from gas royalties for FY 2002 were approximately $103,789,000 for both onshore and offshore leases. 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 affiliated with the lessee. Therefore, we estimate that 75 percent of all gas transportation allowances are 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 2004 Federal oil valuation rulemaking). Based on total gas transportation allowance deductions of $103,789,000 for FY 2002, the percentage of non-arm's-length gas transportation allowances and our assumptions regarding the makeup of the allowance components, the portion of allowances attributable to the rate of return will be approximately $8,649,000 ($103,789,000 × .25 × .3333). 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 will 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. However, the cost of the line loss is calculated based on the value of the gas transported, not on the cost or rate of its transportation. Therefore, the 0.2 percent line loss volume implies a 0.2 percent decrease in the royalty owed on Federal gas subject to transportation. For FY 2002, the royalty reported prior to allowances, for those leases in which a transportation allowance was reported, was approximately $2,506,447,000. Assuming 25 percent of that amount corresponds to gas that was transported under non-arm's-length transportation arrangements, the decrease due to line loss would be $1,253,224 ($2,506,447,000 × .25 × .002), or 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 MMS understands that the cost of a letter of credit generally is based on the volume of gas transported through a pipeline under arm's-length transportation contracts and the creditworthiness of the shipper. We first determined that, based on the total sales volume of gas from Federal onshore and offshore leases of 5,822,000,000 Mcf for FY 2002, approximately 4,892,000,000 Mcf was not taken as Royalty in Kind (RIK). Then we estimated that 80 percent of 4,892,000,000 Mcf from Federal onshore and offshore leases is subject to a transportation allowance and the average onshore and offshore royalty rate is 13.55 percent. Therefore, the portion corresponding to the royalty percentage of the Federal gas sales volume subject to a transportation allowance will be approximately 530,000,000 Mcf (4,892,000,000 × .80 × .1355). Next, we assumed that 75 percent of that volume will be transported at arm's length, and that typical letter of credit costs will be the cost of transporting 2 months' volume (1/6 of the annual volume) at a rate of $0.03 per Mcf. 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 and gas corporations with A or higher credit ratings. Therefore, the net decrease in royalties will be approximately $398,000 (530,000,000 × .75 × 1/6 × $0.03 × .2) annually.

Total Net Decrease in Royalties—Industry.

$2,595,000 + $1,253,000 + 398,000 = $4,246,000.

(4) Net Increase in Royalties—Restrict Use of FERC Tariff Charges.

The MMS has received 94 requests to date to use FERC-approved gas tariffs as an exception to non-arm's-length transportation costs. When approved, these exceptions will continue year after year. For this revenue impact analysis, we assumed that 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 will be nationwide, due to significantly varying market conditions, location differences, and a myriad of tariff structures, we estimated that a reasonable discounted rate that will be paid under the FERC tariff will be 90 percent of the full tariff rate. Therefore, under the new provision, lessees will 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 annually ($103,789,000 × .25 × .5 × .1 = $1,297,000).

(5) Net Increase in Royalties—Eliminate “Grandfather” Clause.

MMS believes that there are few instances of continuing use of valuation determinations that were in effect before 1988 and continued to be in effect under the 1988 Gas Rule. From our audit work on these leases for FY 2002, MMS estimates that royalties will increase under this rule by approximately $5,200,000 annually.

Total Net Increase in Royalties—Industry.

$1,297,000 + $5,200,000 = $6,497,000.

B. State and Local Governments

This rule will not impose any additional burden on local governments.

States receiving a portion of royalties from offshore leases located within the zone defined and governed by section 8(g) of Outer Continental Shelf Lands Act, 43 U.S.C. 1337(g), will share in a portion of the increased or decreased royalties resulting from transportation allowances claimed by industry. To determine the impact for these “8(g) states,” we used a factor of .505 (the portion of gas transportation allowances attributable to offshore production) multiplied by a factor of .0061 (the portion of offshore Federal revenues disbursed to states for section 8(g) leases) to arrive at a factor of .0030805 that we then applied to the net increases or decreases resulting from the calculations in paragraph A.

Onshore states will also share in a portion of the increased or decreased royalties resulting from transportation allowances claimed by industry. To determine the impact on onshore States, we used a factor of .495 (the portion of gas transportation allowances attributable to onshore production) multiplied by a factor of .5 (the approximate overall portion of onshore Federal revenues disbursed to states) to arrive at a factor of .2475 that we then applied to the net increases or decreases resulting from the calculations in paragraph A.

(1) Net Decrease in Royalties—Allow Transportation Deduction for Unused Firm Demand Charges.

There is no impact.

(2) Net Decrease in Royalties—Increase Rate of Return in Non-Arm's-Length Situations From 1 Times the Standard & Poor's BBB Bond Rate to 1.3 Times the Standard & Poor's BBB Bond Rate.

$2,595,000 × .0030805 = $8,000 (for OCS 8(g) states) + $2,595,000 × .2475 = $642,000 (for onshore states) = $650,000.

(3a) Net Decrease in Royalties—Allow Line Loss as a Component of a Non-Arm's-Length Transportation Allowance.

$1,253,000 × .0030805 = $4,000 (for OCS 8(g) states) + $1,253,000 × .2475 = $310,000 (for onshore states) = $314,000.

(3b) Net Decrease in Royalties—Allow the Cost of a Letter of Credit as a Component of an Arm's-Length Transportation Allowance.

$398,000 × .0030805 = $1,000 (for OCS 8(g) states) + $398,000 × .2475 = $99,000 (for onshore states) = $100,000.

Total Net Decrease in Royalties—States.

$650,000 + $314,000 + $100,000 = $1,064,000.

(4) Net Increase in Royalties—Restrict Use of FERC Tariff Charges.

$1,297,000 × .0030805 = $4,000 (for OCS 8(g) states) + $1,297,000 × .2475 = $321,000 (for onshore states) = $325,000.

(5) Net Increase in Royalties—Eliminate “Grandfather” Clause.

$5,200,000 × .5 = $2,600,000 (for onshore states only).

Total Net Increase in Royalties—States.

$325,000 + $2,600,000 = $2,925,000.

The total impact on all states will be a revenue increase of approximately $1,861,000 ($2,925,000-$1,064,000) annually.

C. Federal Government

The Federal Government, like the states, will be affected by a net overall increase in royalties as a result of the changes to the regulations governing transportation allowance computations and the changes effected by § 206.157(c), eliminating the “grandfather” clause. In fact, the royalty increase experienced by the Federal Government will be the difference between the total increased royalty obligations on the industry and the portion of the royalty increase that benefits the states. In other words, the royalty increase to industry will be shared proportionately between the states and the Federal Government as computed below.

(1) Net Decrease in Royalties—Allow Transportation Deduction for Unused Firm Demand Charges.

There is no impact.

(2) Net Decrease in Royalties—Increase Rate of Return in Non-Arm's-Length Situations From 1 Times the Standard & Poor's BBB Bond Rate to 1.3 Times the Standard & Poor's BBB Bond Rate.

$2,595,000 (total decrease)—$650,000 (states' share) = $1,945,000.

(3a) Net Decrease in Royalties—Allow Line Loss as a Component of a Non-Arm's-Length Transportation Allowance.

$1,253,000 (total decrease)−$314,000 (states' share) = $939,000.

(3b) Net Decrease in Royalties—Allow the Cost of a Letter of Credit as a Component of an Arm's-Length Transportation Allowance.

$398,000 (total decrease)−$100,000 (states' share) = $298,000.

Total Net Decrease in Royalties—Federal Government.

$1,945,000 + $939,000 + $298,000 = $3,182,000.

(4) Net Increase in Royalties—Restrict use of FERC Tariff Charges.

$1,297,000 (total increase) − $325,000 (states' share) = $972,000.

(5) Net Increase in Royalties—Eliminate “Grandfather” Clause.

$5,200,000 (total increase)−$2,600,000 (states” share) = $2,600,000.

Total Net Increase in Royalties—Federal Government.

$972,000 + $2,600,000 = $3,572,000.

The net impact on the Federal Government will be a royalty increase of approximately $390,000 ($3,572,000−$3,182,000) annually.

D. Summary of Costs and Royalty Impacts 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	Annual costs and royalty increases or royalty decreases
A. Industry:
(1) Royalty Decrease—Allowable Transportation Deductions (1-3)	−$4,246,000
(2) Royalty Increase—Restrict use of FERC Tariff Charges and Eliminate “Grandfather” Clause (4-5)	6,497,000
(3) Net Expected Change in Royalty Payments from Industry	2,251,000
B. State and Local Governments:
(1) Royalty Decrease—Allowable Transportation Deductions (1-3)	−1,064,000
(2) Royalty Increase “ Restrict use of FERC Tariff Charges and Eliminate “Grandfather” Clause (4-5)	2,925,000
(3) Net Expected Change in Royalty Payments to States	1,861,000
C. Federal Government:
(1) Royalty Decrease—Allowable Transportation Deductions (1-3)	−3,182,000
(2) Royalty Increase—Restrict use of FERC Tariff Charges and Eliminate “Grandfather” Clause (4-5)	3,572,000
(3) Net Expected Change in Royalty Payments to Federal Government	390,000

2. Regulatory Planning and Review, Executive Order 12866

Under the criteria in Executive Order 12866, this 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 rule because it raises novel legal or policy issues.

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

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

4. This rule will raise novel legal or policy issues.

3. Regulatory Flexibility Act

The Department of the Interior certifies this 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.). The rule applies primarily to large, integrated producers who transport their natural gas production through their own pipelines or pipelines owned by major natural gas transmission providers.

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.

4. Small Business Regulatory Enforcement Fairness Act (SBREFA)

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

1. Does not have an annual effect on the economy of $100 million or more. See the above 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.

5. Unfunded Mandates Reform Act

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

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

2. This 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.”

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

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

7. Federalism, Executive Order 13132

In accordance with Executive Order 13132, this 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 rule will not alter any lease management or royalty sharing provisions. It will determine the value of production for royalty computation purposes only. This rule will not impose costs on states or localities.

8. Civil Justice Reform, Executive Order 12988

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

9. Paperwork Reduction Act of 1995

This rulemaking does not contain new information collection requirements or significantly change existing information collection requirements; therefore, a submission to OMB is not required. The information collection requirements referenced in this 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. Under the proposed rule (69 FR 43944, July 23, 2004), we asked for comments regarding any information collection burdens that would arise under a new provision at Section 206.157(b)(5) that would allow lessees an exception 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. We did not receive any comments regarding information collection burdens on that specific provision.

10. National Environmental Policy Act (NEPA)

This 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.

11. 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. This rule does not apply to Indian leases. However, it is theoretically possible that this rule might have a very small impact on the competitiveness of Indian leases in situations where an Indian lease is not in an index zone and the lessee is affiliated with the pipeline that transports the Indian lease production. It is only in those situations that the lessee would have to calculate actual transportation costs using different provisions than prescribed for Federal leases in this final rule. The MMS anticipates that such situations will be extremely rare.

12. 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 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 rule otherwise impact energy supply, distribution, or use.

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

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

14. 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, § 206.157 Determination of Transportation Allowances. (5) What is the purpose of this part? (6) Is the description of the rule in the Supplementary Information section of the preamble helpful in understanding the rule? (7) 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.

List of Subjects in 30 CFR Part 206

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

Dated: February 2, 2005.

Rebecca W. Watson,

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 amended as follows:

PART 206—PRODUCT VALUATION

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

Authority: 5 U.S.C. 301 et seq.; 25 U.S.C. 396, 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 to read 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 10 through 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 & Poor's BBB rating. The BBB rate must be the monthly average rate as published in Standard & 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 filed with the Federal Energy Regulatory Commission (FERC) or a state regulatory agency, that FERC or the state regulatory agency has permitted to become effective, and

(B) Third parties are paying prices, including discounted 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 lesser of the volume-weighted average of the rates paid by the third parties under arm's-length transportation contracts during that production month or the non-arm's-length payment by the lessee to the pipeline.

(iii) 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 the tariff remains in effect and third parties paid such rates, for up to five successive production months. You must use the non-arm's-length payment by the lessee to the pipeline if it is less than the volume-weighted average of the rates paid by third parties under arm's-length 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.

* * * * *

(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;

* * * * *

(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;

* * * * *

(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.

* * * * *