[Federal Register Volume 61, Number 148 (Wednesday, July 31, 1996)] [Proposed Rules] [Pages 39931-39940] From the Federal Register Online via the Government Publishing Office [www.gpo.gov] [FR Doc No: 96-19310] ======================================================================= ----------------------------------------------------------------------- DEPARTMENT OF THE INTERIOR Minerals Management Service 30 CFR Part 206 RIN 1010-AC06 Amendments to Transportation Allowance Regulations for Federal and Indian Leases to Specify Allowable Costs and Related Amendments to Gas Valuation Regulations AGENCY: Minerals Management Service, Interior. ACTION: Proposed rulemaking. ----------------------------------------------------------------------- SUMMARY: The Minerals Management Service (MMS) proposes to amend its regulations governing valuation for royalty purposes of gas produced from Federal and Indian leases. The proposed rule primarily addresses allowances for transportation of gas. The amendments would clarify the methods by which gas royalties and deductions for gas transportation are calculated. DATES: Comments must be submitted on or before September 30, 1996. ADDRESSES: Comments should be sent to: David S. Guzy, Chief, Rules and Procedures Staff, Minerals Management Service, Royalty Management Program, P.O. Box 25165, MS 3101, Denver, Colorado 80225-0165, courier delivery to Building 85, Denver Federal Center, Denver, CO 80225, telephone (303) 231-3432, fax (303) 231-3194, e-Mail David__G[email protected]. FOR FURTHER INFORMATION CONTACT: David S. Guzy, Chief, Rules and Procedures Staff, Minerals Management Service, Royalty Management Program, telephone (303) 231-3432, fax (303) 231-3194, e-Mail David__G[email protected]. SUPPLEMENTARY INFORMATION: The principal authors of this proposed rule are Theresa Walsh Bayani at (303) 275-7247, Susan Lupinski at (303) 275-7246, and Gregory Smith at (303) 275-7102 from MMS's Offices in Lakewood, Colorado, and Geoffrey Heath at (202) 208-3051 and Peter Schaumberg at (202) 208-4036 from the Office of the Solicitor in Washington, D.C. [[Page 39932]] I. General MMS published a set of rules in 30 CFR Part 206 governing gas valuation and gas transportation calculation methods to clarify and codify the departmental policy of granting deductions for the reasonable actual costs of transporting gas from a Federal or Indian lease (when the gas is sold at a market away from the lease) (53 FR 1272, January 15, 1988). Since the 1988 rulemaking, Federal Energy Regulatory Commission (FERC) regulatory actions significantly affected the gas transportation industry. Before these changes, gas pipeline companies served as the primary merchants in the natural gas industry. During that environment, pipelines:Bought gas at the wellhead, Transported the gas, and Sold the gas at the city gate to local distribution companies (LDC). In the mid-1980's, FERC began establishing a competitive gas market, allowing shippers access to the pipeline transportation grid. These actions ensured that willing buyers and sellers could negotiate their own sales transactions. Specifically, starting with the implementation of FERC Order 436, FERC began regulating pipelines as open access transporters and requiring non-discriminatory transportation. This permitted downstream gas users (such as LDC's and industrial users) to buy gas directly from gas merchants in the production area and to ship that gas through interstate pipelines. FERC Order 436 and amendments, plus the elimination of price controls, created a vigorous spot market. Producers and marketers, in competition for the sale of gas to end users, are now transporting substantial volumes of gas that they own through interstate pipelines. In the early 1990's, FERC recognized that pipelines still held an advantage over competing sellers of gas. Pipelines held substantial market power and sold gas bundled with a transportation service. FERC remedied the inequities in the gas market by issuing FERC Order 636, effective May 18, 1992. FERC Order 636: Required the separation (unbundling) of sales and gas transportation services; Enabled the implementation of a capacity release program; and Allowed pipelines to assess shippers surcharges for services such as transition costs and FERC's annual charges (57 FR 13267, April 16, 1992). The unbundled costs--previously embedded in a lump-sum charge-- include: Transmission, Storage, Production, and Gathering costs. MMS reviewed its current gas transportation regulations (30 CFR 206.156 and 206.157 (Federal), and 206.176 and 206.177 (Indian)(1996)) and determined that they provide general authority to calculate transportation deductions for cost components resulting from implementing FERC Order 636 and previous FERC orders. However, MMS determined that we should provide specific guidance to lessees and royalty payors on which transportation service components are deductible transportation costs. This guidance is necessary because transportation service components previously aggregated may now be separately identified in transportation contracts, and new transportation costs unique to the FERC Order 636 environment are emerging. Further, some ``transportation'' service components reflect non- deductible costs of marketing rather than transportation. The purpose of this proposed rule is to clarify for the oil and gas industry which cost components or other charges are deductible (related to transportation) and which costs are not deductible (related to marketing) for Federal and Indian leases. The discussion in this preamble, and the proposed rule, relates primarily to the effects of FERC Order 636 on interstate gas pipelines that FERC regulates. To the extent these same types of changes and issues are relevant for intrastate pipelines, this proposed rule applies equally. In conjunction with the proposed changes to the transportation allowance regulations, MMS also proposes certain changes to the gas valuation regulations. When FERC approves tariffs, they generally allow pipelines to include provisions ensuring that pipelines can maintain operational and financial control of their systems. These provisions may include requirements that shippers maintain pipeline receipts and deliveries within certain daily or monthly tolerances and that shippers ``cash-out'' accumulated imbalances. As explained in more detail below, if a shipper over-delivers production to a pipeline, the pipeline may purchase the excess gas quantities from the shipper. If the gas quantity exceeds certain prescribed tolerances, the shipper may incur a ``penalty'' in the form of a substantially reduced price for that gas. MMS will not accept that ``penalty price'' as the value of production and proposes in this rule a method for valuing production sold under such circumstances. Certain additions to revenues from the sale of natural gas may occur in the gas transportation environment. These issues are gas valuation issues beyond the scope of this rulemaking. However, these additions to revenues may be royalty bearing under existing regulations. MMS also recognizes that certain lessee gas transportation arrangements result in financial transactions not directly associated with the gas value. Such transactions may not have royalty consequences. If a lessee is unsure whether its transactions result in additional royalty obligations, it may request a value determination from MMS as provided in the existing rules. The amendments discussed below apply to both arm's-length and non- arm's-length situations for valuing gas production and calculating transportation allowances. II. Section-by-Section Analysis MMS proposes amending its regulations and deleting the existing Secs. 206.157(f) and 206.177(f) (although MMS retains the substance of this paragraph in a later revised paragraph). We redesignated paragraph (g) of these sections as paragraph (h) and added two new paragraphs. New paragraph (f) describes the types of costs MMS will allow as part of a transportation allowance. A new paragraph (g) lists those costs that MMS expressly disallows. Because some of the nonallowable costs affect valuation, MMS proposes amending Secs. 206.152, 206.153, 206.172 and 206.173. These amendments address valuation of certain ``cash-out'' volumes and expressly reaffirm that marketing costs are not allowable deductions from royalty value. A. Sections 206.152, 206.153, 206.172 and 206.173 How to Value Over- Delivered Volumes Under a ``Cash-Out'' Program See the discussion below at 30 CFR 206.157 and 30 CFR 206.177 for the proposed changes to 30 CFR 206.152, 206.153, 206.172, and 206.173. B. Sections 206.157(f) and 206.177(f) Allowable Costs in Determining Transportation Allowances 1. Firm Demand Charges In Secs. 206.157(f)(1) and 206.177(f)(1), MMS proposes allowing firm demand charges--limited to the applicable rate per MMBtu multiplied by the actual volumes transported--as allowable costs in computing the transportation [[Page 39933]] allowance. FERC Order 636 made significant changes to the structure of interstate gas pipelines services; however, these services and the costs reflected in their rates are not new to the gas industry. Because FERC unbundled these services, MMS determined that certain firm demand costs may be allowable transportation costs. Firm transportation is a service in which the shipper contracts and pays for a capacity entitlement. Pipelines generally provide firm transportation under a two-part rate structure: (a) demand or reservation charges to recover its fixed costs; and (b) a commodity charge which usually recovers its variable costs. In contrast, interruptible transportation is a lower priority service. During peak demand periods on the pipeline system, the pipeline must provide the firm customers' capacity requirements before permitting access to shippers with interruptible service. In Order 636, FERC adopted a rate design allocating 100 percent of the fixed costs of operating the pipeline to the firm demand charge. These costs include: Depreciation; Operation and maintenance costs; and Return on equity. Customers with firm service pay a monthly demand charge, based on the amount of capacity reserved, plus a commodity charge for the variable costs of pipeline operation (on-line compression, etc.). Customers with interruptible service pay only a commodity charge because they do not reserve pipeline capacity. Under the current rules, MMS allows all those costs that were in tariffs because the costs generally were not separately identified. After FERC Order 636, these costs are segregated and MMS allows the costs for firm and interruptible service in determining the transportation allowance for both arm's-length and non-arm's-length contracts. MMS considers firm and interruptible service charges as actual costs of transportation, with certain exceptions discussed below. (See also the discussion below regarding commodity charges in proposed Secs. 206.157(f)(3) and 206.177(f)(3)). MMS recognizes that other valuation implications result from a lessee's choice of securing firm versus interruptible services. For instance, gas transported under firm transportation service will likely command a higher sales price than gas transported under interruptible service. If the gas sales transaction is not arm's-length, the lessee would apply the comparability criteria in Secs. 206.152, 206.153, 206.172 and 206.173 and compare values of gas transported under the same transportation arrangement--firm to firm and interruptible to interruptible. 2. Capacity Release Program The capacity release program reallocates a shipper's unused firm transportation capacity. In low demand periods, shippers with firm transportation release unused capacity to the pipeline. During peak demand periods, shippers with firm transportation maintain their contracted pipeline capacity. When another party acquires released capacity from the pipeline, the pipeline credits the payments to the shipper who released the firm transportation. That transaction could result in a loss or gain to the releasing firm transportation holder. When another shipper does not acquire released capacity, a loss occurs--the capacity holder loses what it paid for some of its firm capacity. In Secs. 206.157(f)(1) and 206.177(f)(1) MMS proposes that such losses to the lessee/holder of firm transportation would not be deductible transportation costs. In addition, the lessee may not include any losses it incurs from receiving less for release of its firm capacity than what it paid. Similarly, any gains from the sale of firm capacity would have no allowance or royalty consequences. MMS does not consider these gains or losses associated with transfers of firm transportation as part of the actual costs of transportation. Therefore, regardless of whether the firm capacity holder makes or loses money on capacity releases, it may only claim the firm demand charge per MMBtu multiplied by the actual volume it transports as its transportation allowance. When a lessee/shipper acquires released capacity on a pipeline, MMS allows the cost of buying that capacity as a transportation cost to the extent the capacity is actually used. 3. Pipeline Rate Adjustments Pipeline rates are sometimes subject to later adjustment; the pipeline may agree to retroactively adjust the effective rate in a rate case settlement, or FERC may order a rate adjustment when it acts on the merits of a rate increase application. For example, a rate reduction may occur if: A pipeline determines that its operating costs are lower than it originally projected; or Its billing determinants are higher. In such cases, the pipeline may have to refund certain revenues it collects; such as penalty revenues. Only in rare instances does FERC allow pipelines to retroactively increase rates. MMS proposes that if the lessee receives a payment or credit from the pipeline for penalty refunds, rate case refunds, or other reasons, the lessee must reduce the firm demand charge used to calculate its transportation allowance reported on the Form MMS-2014, Report of Sales and Royalty Remittance. The lessee must modify the Form MMS-2014 by the amount of the refund or other credit (including any interest the lessee receives from the pipeline) for the affected reporting period. In this situation, the lessee would owe additional royalty. MMS recognizes that this requirement may be administratively burdensome because the lessee may have to amend numerous Forms MMS-2014 for many leases. This may occur if more than one refund for the same lease happens at different times. Please comment on this issue, including suggestions for simplified reporting so that MMS may address the reporting issue either in a final rule or in ``MMS Oil and Gas Payor Handbook'' amendments. 4. Sections 206.157(f)(2) and 206.177(f)(2) Gas Supply Realignment (GSR) Costs In Secs. 206.157(f)(2) and 206.177(f)(2), MMS proposes allowing Gas Supply Realignment (GSR) costs as an allowable transportation cost. GSR costs result from a pipeline reforming or terminating supply contracts with purchasers in implementing the restructuring requirements of FERC Order 636 or subsequent FERC orders. Under FERC Order 636, pipelines may recover 100 percent of their prudently incurred eligible contract settlement costs through charges to their transportation customers. Pipelines allocate: 90 percent of the costs to existing firm transportation customers; and 10 percent to interruptible transportation customers. The pipeline's transportation rate will include these GSR costs which may be embedded in the transportation rates or identified separately as a surcharge. Because FERC allows GSR costs in the basic pipeline transportation rates, MMS considers these costs as an actual cost of transportation under the existing regulations. In this proposed rule, MMS is specifically identifying GSR costs as an allowable cost. This treatment of GSR costs is consistent with MMS's treatment of lump-sum contract settlement payments received by a lessee for amending or terminating gas sales contracts. The proposed rule does not affect the principles governing when and to what [[Page 39934]] extent such payments are or become royalty-bearing, as set forth in the decisions of the Assistant Secretary for Land and Minerals Management and the Assistant Secretary for Indian Affairs in Shell Offshore, Inc., Docket No. MMS-91-0087-OCS (Sept. 2, 1994), and Samedan Oil Corp., Docket No. MMS-94-0003-O&G (Sept. 16, 1994) (upheld on judicial review pending in Samedan Oil Corp. v. Deer, No. 94CV02123 (RCL) (D.D.C. June 14, 1995)), appeal pending, No. 95-5210 (D.C. Cir). Pipelines may recover GSR costs as part of their transportation charges to all their customers. When pipelines impose those charges on gas, this is rarely the gas which was the subject of the reformed or settled contract. Even if it were, the lessee/shipper must pay royalty on part or all of the contract settlement payment. The portion of the payment which is indirectly ``paid back'' to the pipeline through the GSR charge is still allowable as part of the transportation allowance. 5. Sections 206.157(f)(3) and 206.177(f)(3) Commodity Charges Under existing Secs. 206.157 and 206.177, MMS allows costs which are directly related to the transportation of production in the transportation allowance. In Secs. 206.157(f)(3) and 206.177(f)(3), MMS proposes allowing the commodity charges paid to pipelines as allowable costs in computing the transportation allowance. The commodity charge, and the firm demand charge as explained above, allows the pipeline to recover the costs of providing its service. While the firm demand charge represents the fixed costs of operating the pipeline, the commodity charge represents the pipeline's transportation-related variable costs. The pipeline assesses firm transportation shippers a commodity charge based on the quantities of gas actually transported. The pipeline assesses the interruptible transportation shippers a commodity charge or rate for each unit of gas transported. Currently, MMS allows these commodity charges in determining transportation allowances. Under the proposed rule, MMS specifically identifies the commodity charge as an allowable cost. 6. Sections 206.157(f)(4) and 206.177(f)(4) Wheeling Costs In many cases, a lessee transports gas produced from Federal or Indian leases through a market center or hub. A hub is a connected manifold of pipelines through which a series of incoming pipelines are interconnected to a series of outgoing pipelines. For example, gas coming in on Pipeline A may go out of the market hub on Pipeline A or Pipeline B. The transportation of gas from one pipeline through the hub to either the same or another pipeline is known as wheeling. The hub operator charges a fee for the wheeling. MMS proposes allowing wheeling costs in determining transportation allowances in Secs. 206.157(f)(4) and 206.177(f)(4). 7. Sections 206.157(f) (5) and (6) and 206.177(f) (5) and (6) GRI Fees and ACA Fees As part of the standard pipeline tariff, FERC allows pipelines to charge fees to support programs of the Gas Research Institute (GRI). Also, the pipelines include Annual Charge Adjustment (ACA) fees that pay for FERC's operating expenses. Currently, MMS allows the GRI/ACA fees as part of the transportation allowance and will continue to allow them under the proposed rule. 8. Sections 206.157(f)(7) and 206.177(f)(7) Actual or Theoretical Losses Under the existing regulations at 30 CFR 206.157(f) and 206.177(f), if a lessee is charged for actual or theoretical losses under an arm's- length contract, the lessee may deduct the related transportation costs. The rules also allow these costs for non-arm's-length transportation contracts if a FERC or State regulatory agency-approved tariff includes an actual or theoretical loss component. MMS proposes continuing this same provision in the proposed Secs. 206.157(f)(7) and 206.177(f)(7). However, MMS is modifying the wording at Secs. 206.157(f) and 206.177(f) for clarification. There will be no substantive change from the existing rules. 9. Sections 206.157(f)(8) and 206.177(f)(8) Supplemental Services Necessary for Transportation MMS proposes allowing certain supplemental costs for compression, dehydration, and treatment of gas only if the transporter requires such services as part of the transportation process. MMS does not allow any costs for compression, dehydration, and treatment of gas for the purpose of placing gas in marketable condition. It is clear that Federal and Indian lessees must put production in marketable condition at no cost to the lessor (30 CFR 206.152(i), 206.153(i), 206.172(i), and 206.173(i)(1995)); Mesa Operating Limited Partnership v. Department of the Interior, 931 F.2d 318 (5th Cir. 1991), cert. denied, 112 S.Ct. 934 (1992).) Therefore, MMS requires the lessee to compress, dehydrate, sweeten, and otherwise treat the gas to place it in the condition necessary to meet typical requirements for gas purchase contracts or pipeline standards. MMS recognizes, however, that there may be unusual circumstances where the pipeline performs additional compression, dehydration, or other treatment of gas to remove impurities during the transportation process. Under the proposed rule, if the lessee demonstrates that the costs it incurs for these treatment purposes are not related to the treatment required to put the gas in marketable condition, then the lessee can include these costs in its transportation allowance. MMS will not allow transportation deductions for: Any costs necessary to bring production up to the required pipeline system standards; or Any indirect costs included by the lessee for these treatment services. This situation occurs when the pipeline treats the gas to put it in marketable condition and then increases other transportation costs billed to the lessee/shipper. These supplemental costs are not the costs already included in the calculation of the pipeline's operational costs for firm and interruptible demand charges. C. Sections 206.157(g) and 206.177(g) Nonallowable Costs in Determining Transportation Allowances FERC Order 636 and other FERC orders--designed to increase competition in the natural gas industry--substantially changed the structure of gas transportation and sales transactions. Clearly, some costs are for marketing gas production and are not for costs incurred to transport gas. Lessees cannot deduct from royalty value the costs of marketing production from Federal and Indian leases. For decades, the regulations required that the lessee place production in marketable condition at no cost to the lessor. Thus, if the purchaser incurs costs to market the production, the lessee may not reduce the royalty value (either directly or through the transportation allowance) to compensate the purchaser for those marketing costs. Neither may the lessee pay another entity for marketing services and deduct the costs of those services from the royalty value. The Interior Board of Land Appeals (IBLA) supported this principle in Walter Oil and Gas Corporation, 111 IBLA 265 (1989). IBLA concluded that a lessee may not deduct the costs of [[Page 39935]] finding markets for gas, regardless of whether it uses its own employees to market the gas or contracts out those functions. Similarly, if a purchaser reduces the price paid to the lessee for any costs of marketing transactions, the lessee must adjust the price upward by the amount of these costs when it reports value for royalty purposes. This principle derives from the lessee's implied covenant to market production for the mutual benefit of the lessee and the lessor. Because the implied covenant to market is the lessee's obligation, the lessor does not share in the marketing costs. This implied covenant and the marketable condition rule require the lessee to market the gas at its own expense. The proposed rule adds specific language to paragraph (i) of 30 CFR 206.152, 206.153, 206.172, and 206.173 to expressly state the lessee's obligation to incur all marketing costs. In all sections, MMS will amend paragraph (i) to add the words ``and to market the gas for the mutual benefit of the lessee and the lessor'' after the words ``place gas in marketable condition'' and before the words ``at no cost to the Federal government (or Indian lessor, as applicable).'' MMS will also add the words ``or to market the gas'' at the end of the last sentence of that paragraph to accomplish this objective. MMS believes that the added language contains the concept embodied in the implied covenant to market for the mutual benefit of Federal and Indian oil and gas leases. Because of the developing gas market, transporters, purchasers, or marketers charge producers for various marketing costs. MMS will not allow: The costs of these transactions as a transportation deduction; or Any reduction in gas sales value by the lessee when the purchaser performs these services. Under the proposed rule, the following transactions fall under the non-deductible ``marketing costs'' category: Sections 206.157(g)(1) and 206.177(g)(1) Storage fees. Under the proposed rule, MMS will not allow gas storage costs as part of the costs of transportation. This includes long-term storage and short duration storage (often less than one day). The short duration storage is often known as ``banking'' or ``parking'' and frequently occurs at a marketing center or hub. MMS will disallow costs for other temporary storage during the transportation process (whether the storage actually occurs or is solely a matter of accounting convenience). MMS considers these costs as marketing costs. However, MMS recognizes that these temporary storage costs are different from longer term storage. Please comment on whether and why MMS should allow these costs under paragraph (f) of this section. Off-lease storage for marketing purposes also has an effect on the royalty value of stored production. The regulation at 30 CFR Sec. 202.150 (1995), the language of the various mineral leasing statutes, and terms of Federal leases require that royalty be a percentage of the amount or value of the production removed or sold from the lease. MMS considers gas removed from a Federal or Indian lease and stored at a location off the lease for future sale subject to royalty at the time of removal from the lease. In this situation, the lessee would determine the value of the gas production by applying the provisions of 30 CFR 206.152 and 206.172 (unprocessed gas), or 206.153 and 206.173 (1995) (processed gas) because there is no arm's-length sale at the time of production and removal from the lease. (See BWAB, Inc., 108 IBLA 250 (1989)). If a lessee accumulated its production off- lease during periods when demand was low and sold those accumulated volumes in a later period, the prices realized upon sale may be higher or lower than those available at the time of production. MMS would not share in any increase or decrease in value resulting from storing gas as part of the lessee's marketing strategy. This appears to be an exception to the gross proceeds rule; in this circumstance, MMS would not look to the lessee's proceeds at the time of later sale because MMS required the lessee to pay royalty on the value of the gas at the time of its removal from the lease. Sections 206.157(g)(2) and 206.177(g)(2) Aggregator/marketer fees. Aggregator/marketer fees are fees a producer pays to another person or company (including its affiliates) to market its gas. Aggregator/ marketer fees are similar to commissions or fees paid to another party for that party's costs of finding or maintaining a market for the gas production. Under the proposed rule, MMS will not allow these costs as a transportation deduction. Sections 206.157(g)(3) and 206.177(g)(3) Penalties. FERC allows pipelines to impose ``penalties'' or economic disincentives for shipper actions that threaten the pipeline's operational integrity or cause an unnecessary financial burden to the pipeline. The following are the most common types of penalties: Cash-out penalties. Scheduling penalties. Imbalance penalties. Curtailment and operational flow order penalties. (i) Cash-out penalties. Many pipelines require monthly or daily imbalance cash-outs of pipeline receipts and deliveries. Over-delivery and underdelivery imbalances which exceed a specified tolerance or threshold (such as 5 percent) may be subject to a penalty. For example, if a lessee/producer delivers greater volumes than the tolerances established in the transportation contract permit, the pipeline will purchase the volumes exceeding the producer's nominated volumes. This is known as ``cashing-out'' the over-deliveries to the pipeline. Transportation contracts usually express the penalty as a percentage reduction or addition to the cash-out index or reference price. Generally, the pipeline purchases excess volumes within the tolerances at a base-index price (such as a monthly average or reference spot-market price) for buying and selling imbalances. For volumes exceeding the stated tolerances, the pipeline purchases or cashes-out at a reduced price such as 90 percent of the index price. The penalties usually increase with an increasing percentage of over- delivery. MMS views price reductions for volume differences outside the specified tolerances as costs incurred as a result of the lessee's breaching its duty to market the production for the mutual benefit of the lessee and lessor. (This is also true in the case of scheduling penalties, imbalance penalties, and operational penalties discussed below.) MMS believes that the lessee can avoid this situation because there are a variety of mitigating devices available to help the lessee balance production and nominations. Examples include: 1. Swapping imbalances or transferring them among the purchasers' contracts; 2. Establishing debit/credit accounts (commonly called ``U- accounts'') with the pipeline for the shipper to carry over its imbalances into subsequent months; 3. Using electronic bulletin boards to adjust for variations between deliveries and nominations on a daily basis, or using swing supplies and flexible receipt point authority to make adjustments; 4. Entering into predetermined allocation agreements with other shippers using the same pipeline receipt points; and 5. Insisting the operators of the upstream facilities at receipt points enter into operational balancing agreements with downstream transporters. [[Page 39936]] Therefore, the proposed rule specifies that the lessee may not deduct as a transportation cost any reduction in sales price for over- delivered volumes outside the specified tolerances. This cost to the lessee is a marketing expense the lessee must bear. In addition to penalties under cash-out programs, MMS also looked at the implications cash-outs have on gas value for royalty purposes. Under the cash-out programs, when the over-deliveries are within the tolerances, the transporter's contract price (for example, the base- index price or referenced spot-market price) generally results in reasonable values. If the transporter's purchase of the excess volumes is under an arm's-length contract, MMS believes generally that there's no reason not to accept the purchase price for those volumes as royalty value under the existing regulations. If the transporter's purchase is under a non-arm's-length contract, the lessee will value the excess volumes under the benchmarks established in the existing rules. Thus, for excess deliveries to the pipeline within the tolerances, there appears to be no reason to change existing rules. Although the over-deliveries within tolerances may represent reasonable value, MMS does not consider the pipeline's purchase of excess volumes outside the tolerances at a reduced penalty price as a reasonable value for royalty purposes. The lessee's failure to conform its deliveries to the pipeline requirements should not prejudice the lessor's royalty interest. Thus, the proposed rule amends paragraph (b)(1) of 30 CFR 206.152 and 206.172 (unprocessed gas), and 206.153 and 206.173 (processed gas) by adding another exception to the general rule that the gross proceeds under an arm's-length contract are acceptable as the royalty value. This new exception adds paragraph (iv) to these sections and provides that over-delivered volumes outside the pipeline tolerances are valued at the same price the pipeline purchases over-delivered volumes within the tolerances. MMS will not accept the penalty ``cash-out'' price as royalty value. The proposed rule also would provide that if MMS determines that the ``cash-out'' price is unreasonably low, it would require the lessee to use the benchmarks to value the gas instead of the cash-out price. Also note that for production from Indian leases, other valuation provisions in the regulations apply; i.e., major portion and dual accounting. (ii) Scheduling penalties. When differences in the volume between scheduled and actual pipeline receipts occur, shippers pay fees or penalties for scheduling (daily differences). This can occur when daily inputs differ from volumes scheduled or nominated at a receipt point and are outside the tolerance specified in the transportation contract or tariff. Under the proposed rule, the lessee cannot deduct these penalties as a transportation allowance. (iii) Imbalance penalties. When differences in the volume between the pipeline's scheduled deliveries occur and are outside the tolerance specified in the transportation contract or tariff, shippers pay fees or penalties for imbalances on a daily or monthly basis. (Note: Pipelines do not assess imbalance penalties and cash-out penalties for the same violation.) Under the proposed rule, the lessee cannot deduct these penalties as a transportation allowance. (iv) Operational penalties. Operational penalties are fees the shipper pays to the transporter for violation of curtailment or operational flow orders (for example, orders the pipeline issues to remedy a situation which threatens the integrity of the pipeline). Under the proposed rule, the lessee cannot deduct these penalties as a transportation allowance. Sections 206.157(g)(4) and 206.177(g)(4) Intra-hub title transfer fees. When the pipeline transports gas through a market center or hub, the hub operator may also assess a fee for administrative services to account for the sale of gas within a hub (known as title transfer tracking). The hub operator assesses these fees as part of the sales transaction for gas at the hub--not as part of the transportation through the hub. Thus, in Secs. 206.157(f)(4) and 206.177(f)(4), MMS is not allowing such fees as part of the transportation allowance. Sections 206.157(g)(5) and 206.177(g)(5) Other nonallowable costs. MMS proposes including a general provision in paragraph (g)(5) of both sections. This provision prohibits the lessee from deducting costs in its transportation allowance for services the lessee must provide at no cost to the lessor. Lessees may attempt to use the transportation allowance deduction for costs which the lessee must bear. This provision prevents lessees from relabeling or restructuring these transactions. For example, most lessees/shippers invest substantial sums in computer software to gain access to pipelines' electronic bulletin boards. Bulletin boards enable the lessee to exchange data and participate in capacity release transactions. MMS will not allow such costs as part of a transportation allowance. III. Other Matters Retroactive Effective Date Gas sales and transportation transactions continue to evolve under the series of FERC Orders discussed above. As noted previously, MMS believes most of the proposed changes to the transportation allowance rules in Secs. 206.157 and 206.177 are generally consistent with the existing rule. Thus, applying the existing rules should, in most circumstances, result in the same transportation allowance as under the proposed rule. MMS proposes to make the changes to the valuation and transportation rules effective May 18, 1992, the effective date of FERC Order 636. MMS wants to avoid any potential inequities for those lessees already operating in the FERC Order 636 environment. Some changes may have occurred in the gas market before FERC Order 636. Please comment on whether an earlier retroactive effective date is appropriate. Indian Leases Although this proposed rule applies to both Federal and Indian mineral leases, MMS recently separated its existing valuation and transportation regulations into individual sections for Federal and Indian leases. Additionally, a negotiated rulemaking committee composed of Indian, industry, and MMS representatives is developing new regulations for gas valuation on Indian leases (identified in the semi- annual regulatory agenda by identifier RIN 1010-AB57) which may replace allowances with an index method in areas where there are published indices. When these new regulations become final, the regulations in this proposed rulemaking may be superseded. Under the Department of the Interior--Department Manual Part 512, Chapter 2, MMS prepared an analysis of the potential impacts of this rule on Indian trust resources. Our analysis shows that the rule will likely have a neutral or beneficial impact on Indian royalties. During the comment period for this proposed rule, we will also accept comments on the analysis. For a copy of this analysis, please contact David S. Guzy, Chief, Rules and Procedures Staff, Telephone (303) 231-3432, FAX, (303) 231-3194. A complete set of the public comments and the economic analysis will be made available on the Internet at www.rmp.mms.gov. Federal Valuation Negotiated Rulemaking A negotiated rulemaking committee recently developed separate regulations [[Page 39937]] concerning gas valuation for royalty purposes on Federal leases. This committee addressed both gas valuation and transportation deduction issues. The proposed regulations developed by this committee (Federal Register, 60 FR 56007, November 6, 1995) are not intended to affect this proposed rule. IV. Procedural Matters The Regulatory Flexibility Act The Department certifies that this rule will not have a significant economic effect on a substantial number of small entities under the Regulatory Flexibility Act (5 U.S.C. 601 et seq.). The proposed rule enhances the valuation and transportation regulations for natural gas to clarify the deductibility of costs under FERC Order 636. Executive Order 12630 The Department certifies that the rule does not represent a governmental action capable of interference with constitutionally protected property rights. Thus, there is no need to prepare a Takings Implication Assessment under Executive Order 12630, ``Government Action and Interference with Constitutionally Protected Property Rights.'' Executive Order 12866 This proposed rule does not meet the criteria for a significant rule requiring review by the Office of Management and Budget under E.O. 12866. Executive Order 12988 The Department has certified to OMB that this proposed regulation meets the applicable standards provided in Section 3(a) and 3(b)(2) of E.O. 12988. Unfunded Mandates Reform Act of 1995 The Department of the Interior has determined and certifies according to the Unfunded Mandates Reform Act, 2 U.S.C. 1502 et seq., that this rule will not impose a cost of $100 million or more in any given year on local, tribal, State governments, or the private sector. Paperwork Reduction Act The Office of Management and Budget approved the information collection requirements contained in this rule under 44 U.S.C. 3501 et seq., and assigned Clearance Numbers 1010-0022, 1010-0061, and 1010- 0075. This proposed rule does not require additional recordkeeping. National Environmental Policy Act of 1969 We determined that this rulemaking is not a major Federal Action significantly affecting the quality of the human environment, and a detailed statement under section 102(2)(C) of the National Environmental Policy Act of 1969 (42 U.S.C. 4332(2)(C)) is not required. List of Subjects in 30 CFR 206 Coal, Continental Shelf, Geothermal energy, Government contracts, Indian lands, Mineral royalties, Natural gas, Petroleum, Public lands-- mineral resources, Reporting and recordkeeping requirements. Dated: July 15, 1996. Sylvia V. Baca, Deputy Assistant Secretary--Land and Minerals Management. For the reasons set out in the preamble, MMS proposes to amend 30 CFR Part 206 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 et seq., 396a et seq., 2101 et seq.; 30 U.S.C. 181 et seq., 351 et seq., 1001 et seq., 1701 et seq.; 31 U.S.C. 9701; 43 U.S.C. 1301 et seq., 1331 et seq., and 1801 et seq. Subpart D--Federal Gas 2. Section 206.152 is amended by revising the first sentence of paragraph (b)(1)(i) and adding a new paragraph (b)(1)(iv) to read as follows: Sec. 206.152 Valuation standards--unprocessed gas. * * * * * (b)(1)(i) The value of gas sold under an arm's-length contract is the gross proceeds accruing to the lessee except as provided in paragraphs (b)(1)(ii), (iii), and (iv) of this section. * * * * * * * * (iv) How to value over-delivered volumes under a ``cash-out'' program. This paragraph applies to situations where a pipeline purchases gas from a lessee according to a ``cash-out'' program under a transportation contract. For all over-delivered volumes, the royalty value is the price the pipeline is required to pay for volumes within the tolerances for over-delivery specified in the transportation contract. Use the same value for volumes that exceed the over-delivery tolerances even if those volumes are subject to a lower price under the transportation contract. However, if MMS determines that the price specified in the transportation contract for over-delivered volumes is unreasonably low, the lessee must value all over-delivered volumes under paragraph (c)(2) or (c)(3) of this section. 3. In Sec. 206.152, paragraph (i) is revised to read as follows: Sec. 206.152 Valuation standards--unprocessed gas. * * * * * (i) The lessee must place gas in marketable condition and market the gas for the mutual benefit of the lessee and the lessor at no cost to the Federal Government unless the lease agreement states otherwise. Where the value established under this section is determined by a lessee's gross proceeds, that value shall be increased to the extent that the gross proceeds have been reduced because the purchaser, or any other person, is providing certain services the cost of which ordinarily is the responsibility of the lessee to place the gas in marketable condition or to market the gas. * * * * * 4. Section 206.153 is amended by revising the first sentence of paragraph (b)(1)(i) and adding a new paragraph (b)(1)(iv) to read as follows: Sec. 206.153 Valuation standards--processed gas. * * * * * (b)(1)(i) The value of residue gas or any gas plant product sold under an arm's-length contract is the gross proceeds accruing to the lessee, except as provided in paragraphs (b)(1) (ii), (iii), and (iv) of this section. * * * * * * * * (iv) How to value over-delivered volumes under a ``cash-out'' program. This paragraph applies to situations where a pipeline purchases gas from a lessee according to a ``cash-out'' program under a transportation contract. For all over-delivered volumes, the royalty value is the price the pipeline is required to pay for volumes within the tolerances for over-delivery specified in the transportation contract. Use the same value for volumes that exceed the over-delivery tolerances even if those volumes are subject to a lower price under the transportation contract. However, if MMS determines that the price specified in the transportation contract for over-delivered volumes is unreasonably low, the lessee must value all over-delivered volumes under paragraph (c)(2) or (c)(3) of this section. * * * * * 5. Section 206.153 is amended by revising paragraph (i) to read as follows: Sec. 206.153 Valuation standards--processed gas. * * * * * (i) The lessee must place residue gas and gas plant products in marketable condition and market the residue gas and gas plant products for the mutual benefit of the lessee and the lessor at no cost to the Federal Government unless [[Page 39938]] the lease agreement states otherwise. Where the value established under this section is determined by a lessee's gross proceeds, that value shall be increased to the extent that the gross proceeds have been reduced because the purchaser, or any other person, is providing certain services the cost of which ordinarily is the responsibility of the lessee to place the residue gas or gas plant products in marketable condition or to market the residue gas and gas plant products. * * * * * 6.-8. In Sec. 206.157, paragraph (f) is removed; paragraph (g) is redesignated as paragraph (h) and revised; and new paragraphs (f) and (g) are added to read as follows: Sec. 206.157 Determination of transportation allowances. * * * * * (f) Allowable costs in determining transportation allowances. The lessee may include, but is not limited to, 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: (1) Firm demand charges paid to pipelines. The lessee must limit the allowable costs for the firm demand charges to the applicable rate per MMBtu multiplied by the actual volumes transported. The lessee may not include any losses incurred for previously purchased but unused firm capacity. The lessee also may not include the difference between what is paid and any credits received from the pipeline for releasing firm capacity. If the lessee receives a payment or credit from the pipeline for penalty refunds, rate case refunds, or other reasons, the lessee must reduce the firm demand charge claimed on the Form MMS-2014. The lessee must modify the Form MMS-2014 by the amount received or credited for the affected reporting period; (2) Gas supply realignment (GSR) costs. The GSR costs result from a pipeline reforming or terminating supply contracts with producers to implement the restructuring requirements of FERC Orders in 18 CFR Part 284; (3) Commodity charges. The commodity charge allows the pipeline to recover the costs of providing service; (4) Wheeling costs. Hub operators charge a wheeling cost for transporting gas from one pipeline to either the same or another pipeline through a market center or hub. A hub is a connected manifold of pipelines through which a series of incoming pipelines are interconnected to a series of outgoing pipelines; (5) Surcharges or fees to support programs of the Gas Research Institute (GRI). The GRI conducts research, development, and commercialization programs on natural gas related topics for the benefit of the U.S. gas industry and gas customers; (6) Annual Charge Adjustment (ACA) fees. FERC charges these fees to pipelines to pay for its operating expenses; (7) Payments (either volumetric or in value) for actual or theoretical losses. This paragraph does not apply to non-arm's-length transportation arrangements unless the transportation allowance is based on a FERC or State regulatory-approved tariff; and (8) Supplemental costs for compression, dehydration, and treatment of gas. MMS allows these costs only if such services are required for transportation and exceed the services necessary to place production into marketable condition required under Secs. 206.152(i) and 206.153(i) of this part. (g) Nonallowable costs in determining transportation allowances. The lessee cannot include 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: (1) Fees or costs incurred for storage. This includes: (i) Storing production in a storage facility, whether on or off the lease; and (ii) Temporary storage services offered by market centers or hubs (commonly referred to as ``parking'' or ``banking''), or other temporary storage services provided by pipeline transporters, whether actual or provided as a matter of accounting; (2) Aggregator/marketer fees. This includes fees the lessee pays to another person (including its affiliates) to market the lessee's gas, including purchasing and reselling the gas, or finding or maintaining a market for the gas production; (3) Penalties the lessee incurs as shipper. These penalties include, but are not limited to: (i) Over-delivery ``cash-out'' penalties. Includes the difference between the price the pipeline pays the lessee for over-delivered volumes outside the tolerances and the price the lessee receives for over-delivered volumes within the tolerances; (ii) ``Scheduling'' penalties. Includes penalties the lessee incurs for differences between daily volumes delivered into the pipeline and volumes scheduled or nominated at a receipt or delivery point; (iii) ``Imbalance'' penalties. Includes penalties the lessee incurs (generally on a monthly basis) for differences between volumes delivered into the pipeline and volumes scheduled or nominated at a receipt or delivery point; and (iv) ``Operational'' penalties. Includes fees the lessee incurs for violation of the pipeline's curtailment or operational orders issued to protect the operational integrity of the pipeline; (4) Costs for intra-hub transfer fees paid to hub operators for administrative services (e.g., title transfer tracking) necessary to account for the sale of gas within a hub; and (5) Any cost the lessee incurs for services it is required to provide at no cost to the lessor. (h) Other transportation cost determinations. This section applies when calculating transportation costs to establish value using a netback procedure or any other procedure that requires deduction of transportation costs. Subpart E--Indian Gas 9. Section 206.172 is amended by revising the first sentence of paragraph (b)(1)(i) and adding a new paragraph (b)(1)(iv) to read as follows: Sec. 206.172 Valuation standards--unprocessed gas. * * * * * (b)(1)(i) The value of gas sold under an arm's-length contract is the gross proceeds accruing to the lessee except as provided in paragraphs (b)(1) (ii), (iii), and (iv) of this section. * * * * * * * * (iv) How to value over-delivered volumes under a ``cash-out'' program. This paragraph applies to situations where a pipeline purchases gas from a lessee according to a ``cash-out'' program under a transportation contract. For all over-delivered volumes, the royalty value is the price the pipeline is required to pay for volumes within the tolerances for over-delivery specified in the transportation contract. Use the same value for volumes that exceed the over-delivery tolerances even if those volumes are subject to a lower price under the transportation contract. However, if MMS determines that the price specified in the transportation contract for over-delivered volumes is unreasonably low, the lessee must value all over-delivered volumes under paragraph (c)(2) or (c)(3) of this section. 10. Section 206.172 is amended by revising paragraph (i) to read as follows: [[Page 39939]] Sec. 206.172 Valuation standards--unprocessed gas. * * * * * (i) The lessee must place gas in marketable condition and market the gas for the mutual benefit of the lessee and the lessor at no cost to the Indian lessor unless the lease agreement states otherwise. Where the value established under this section is determined by a lessee's gross proceeds, that value shall be increased to the extent that the gross proceeds have been reduced because the purchaser, or any other person, is providing certain services the cost of which ordinarily is the responsibility of the lessee to place the gas in marketable condition or to market the gas. * * * * * 11. Section 206.173 is amended by revising the first sentence of paragraph (b)(1)(i) and adding a new paragraph (b)(1)(iv) to read as follows: Sec. 206.173 Valuation standards--processed gas. * * * * * (b)(1)(i) The value of residue gas or any gas plant product sold under an arm's-length contract is the gross proceeds accruing to the lessee, except as provided in paragraphs (b)(1) (ii), (iii), and (iv) of this section. * * * * * * * * (iv) How to value over-delivered volumes under a ``cash-out'' program. This paragraph applies to situations where a pipeline purchases gas from a lessee according to a ``cash-out'' program under a transportation contract. For all over-delivered volumes, the royalty value is the price the pipeline is required to pay for volumes within the tolerances for over-delivery specified in the transportation contract. Use the same value for volumes that exceed the over-delivery tolerances even if those volumes are subject to a lower price under the transportation contract. However, if MMS determines that the price specified in the transportation contract for over-delivered volumes is unreasonably low, the lessee must value all over-delivered volumes under paragraph (c)(2) or (c)(3) of this section. * * * * * 12. Section 206.173 is amended by revising paragraph (i) to read as follows: Sec. 206.173 Valuation standards--processed gas. * * * * * (i) The lessee must place residue gas and gas plant products in marketable condition and market the residue gas and gas plant products for the mutual benefit of the lessee and the lessor at no cost to the Indian lessor unless the lease agreement states otherwise. Where the value established under this section is determined by a lessee's gross proceeds, that value shall be increased to the extent that the gross proceeds have been reduced because the purchaser, or any other person, is providing certain services the cost of which ordinarily is the responsibility of the lessee to place the residue gas or gas plant products in marketable condition or to market the residue gas and gas plant products. * * * * * 13.-15. In Sec. 206.177, paragraph (f) is removed; paragraph (g) is redesignated as paragraph (h) and revised; and new paragraphs (f) and (g) are added to read as follows: Sec. 206.177 Determination of transportation allowances. * * * * * (f) Allowable costs in determining transportation allowances. The lessee may include, but is not limited to, 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: (1) Firm demand charges paid to pipelines. Limit the allowable costs for the firm demand charges to the applicable rate per MMBtu multiplied by the actual volumes transported. The lessee may not include any losses incurred from not using its previously purchased firm capacity. Nor may the lessee include the difference between what is paid and any credits received from the pipeline for releasing firm capacity. If the lessee receives a payment or credit from the pipeline for penalty refunds, rate case refunds, or other reasons, the lessee must reduce the firm demand charge claimed on the Form MMS-2014. The lessee must modify the Form MMS-2014 by the amount received or credited for the affected reporting period; (2) Gas supply realignment (GSR) costs. The GSR costs result from a pipeline reforming or terminating supply contracts with producers to implement the restructuring requirements of FERC Orders in 18 CFR Part 284; (3) Commodity charges. The commodity charge allows the pipeline to recover the costs of providing service; (4) Wheeling costs. Hub operators charge a wheeling cost for transporting gas from one pipeline to either the same or another pipeline through a market center or hub. A hub is a connected manifold of pipelines through which a series of incoming pipelines are interconnected to a series of outgoing pipelines; (5) Surcharges or fees to support programs of the Gas Research Institute (GRI). The GRI conducts research, development, and commercialization programs on natural gas related topics for the benefit of the U.S. gas industry and gas customers; (6) Annual Charge Adjustment (ACA) fees. FERC charges these fees to pipelines to pay for its operating expenses; (7) Payments (either volumetric or in value) for actual or theoretical losses. This paragraph does not apply to non-arm's-length transportation arrangements unless the transportation allowance is based on a FERC or State regulatory-approved tariff; and (8) Supplemental costs for compression, dehydration, and treatment of gas. MMS allows these costs only if such services are required for transportation and exceed the services necessary to place production into marketable condition required under Secs. 206.172(i) and 206.173(i) of this part. (g) Nonallowable costs in determining transportation allowances. The lessee cannot include 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: (1) Fees or costs incurred for storage. This includes: (i) Storing production in a storage facility, whether on or off the lease; and (ii) Temporary storage services offered by market centers or hubs (commonly referred to as ``parking'' or ``banking''), or other temporary storage services provided by pipeline transporters, whether actual or provided as a matter of accounting; (2) Aggregator/marketer fees. This includes fees the lessee pays to another person (including its affiliates) to market the lessee's gas, including purchasing and reselling the gas, or finding or maintaining a market for the gas production; (3) Penalties the lessee incurs as shipper. These penalties include, but are not limited to: (i) Over-delivery ``cash-out'' penalties. Includes the difference between the price the pipeline pays the lessee for over-delivered volumes outside the tolerances and the price the lessee receives for over-delivered volumes within the tolerances; (ii) ``Scheduling'' penalties. Includes penalties the lessee incurs for differences between daily volumes delivered into the pipeline and volumes scheduled or nominated at a receipt or delivery point; [[Page 39940]] (iii) ``Imbalance'' penalties. Includes penalties the lessee incurs (generally on a monthly basis) for differences between volumes delivered into the pipeline and volumes scheduled or nominated at a receipt or delivery point; and (iv) ``Operational'' penalties. Includes fees the lessee incurs for violation of the pipeline's curtailment or operational orders issued to protect the operational integrity of the pipeline; (4) Costs for intra-hub transfer fees paid to hub operators for administrative services (e.g., title transfer tracking) necessary to account for the sale of gas within a hub; and (5) Any cost the lessee incurs for services it is required to provide at no cost to the lessor. (h) Other transportation cost determinations. This section applies when calculating transportation costs to establish value using a netback procedure or any other procedure that requires deduction of transportation costs. [FR Doc. 96-19310 Filed 7-30-96; 8:45 am] BILLING CODE 4310-MR-P