Amendments to Transportation Allowance Regulations for Federal and Indian Leases to Specify Allowable Costs and Related Amendments to Gas Valuation Regulations

Federal RegisterJul 31, 1996

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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.

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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

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