[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