[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]
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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__Guzy@smtp.mms.gov.
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__Guzy@smtp.mms.gov.
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
