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

Federal RegisterDec 16, 1997

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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: Final rulemaking.

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SUMMARY: The Minerals Management Service (MMS) is amending its

regulations governing valuation for royalty purposes of gas produced

from Federal and Indian leases. The rule primarily addresses allowances

for transportation of gas. The amendments clarify the methods by which

gas royalties and deductions for gas transportation are calculated.

DATE: Effective February 1, 1998.

ADDRESSES: David S. Guzy, Chief, Rules and Publications Staff, Royalty

Management Program, Minerals Management Service, P.O. Box 25165, MS

3021, Denver, Colorado 80225-0165; courier delivery to Building 85,

Denver Federal Center, Denver, Colorado 80225, telephone (303) 231-

3432, FAX (303) 231-3385, e-Mail David__G[email protected].

FOR FURTHER INFORMATION CONTACT: David S. Guzy, Chief, Rules and

Publications Staff, Royalty Management Program, Minerals Management

Service, phone (303) 231-3432, FAX (303) 231-3385, e-Mail

David__G[email protected].

SUPPLEMENTARY INFORMATION: The principal authors of this rule are

Theresa Walsh Bayani and Susan Lupinski, from Royalty Valuation

Division, MMS, Lakewood, Colorado.

I. Background

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 have 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 nondiscriminatory transportation. This permitted downstream

gas users (such as LDCs 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. Under the provisions of this order, FERC:

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.

Necessity for This Rulemaking

We reviewed our current gas transportation regulations (30 CFR

206.156 and 206.157 (for Federal leases), and 206.176 and 206.177 (for

Indian leases) (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, we have determined that lessees and royalty payors need

specific guidance and certainty on which components are deductible as

transportation costs from royalty. This guidance is necessary because

components previously aggregated and unidentifiable may now be

separately identified in transportation contracts, and new costs unique

to the FERC Order 636 environment are emerging.

Further, some of the components reflect non-deductible costs of

marketing rather than transportation. We believe that without the

clarification provided in this rule, lessees and payors

[[Page 65754]]

may claim improper deductions on their royalty reports and payments.

We issued a proposed rulemaking 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 (61 FR 39931, July 31, 1996).

The purpose of this rulemaking is also to clarify our existing

policies. We received comments from 18 separate entities: Six responses

from companies, six responses from industry trade associations, two

responses from State representatives, one response from a State/Indian

association, two responses from Indian tribes, and one response from an

Indian tribal association.

This final rulemaking 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, our rule applies equally.

In conjunction with the changes to the transportation allowance

regulations, we are also making 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. 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. We will not accept that penalty price as the value

of production, and this rulemaking provides 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.

We also recognize 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 you are unsure whether your transactions result in

additional royalty obligations, you may request valuation guidance from

us.

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. Comments on Proposed Rule

We published a proposed rule at 61 FR 39931, 7/31/96. The proposed

rulemaking provided for a 60-day public comment period which ended

September 30, 1996, and was extended to October 30, 1996 (61 FR 48872,

9/17/96).

General Comments

The tribes believe that allowable deductions should be scrupulously

examined and limited to the minimum amount for the economic best

interest of the lessor tribe. They state that FERC-approved tariffs are

not the actual, reasonable cost of transportation paid by the producer

and should not be accepted. A few commenters stated that careful

examination of tariffs is needed to assure revenue protection and

accountability. These respondents claim that lessees believe tariffs

are beyond our scrutiny once we permitted their use. They urge us to

clearly state in this rulemaking that review of costs included in a

tariff is not beyond audit review and that transportation allowances

may be recalculated when the tariff does not reasonably reflect a

lessee's actual costs.

One State commented that under no circumstances should the lessee

be allowed to deduct transportation costs, including tariffs, in excess

of the actual, reasonable costs incurred or paid, regardless of whether

the transportation is arm's-length or non-arm's-length. One tribe and

one Indian tribal association suggested that the preamble language

should specify that allowances are limited to reasonable actual costs

of transportation and are limited to no more than 50 percent of the

value of the production. One tribe believes that this regulation

changes the annual rent or royalty rate without the written consent of

the tribe.

Several States and Indian commenters claim that clarifying the

allowable charges under FERC Order 636 is important and pressing and

urged us not to consider this rule an end to transportation allowance

issues. They believe each cost must be evaluated against the lessees'

duty to market production and that marketing costs are not a deductible

expense. They also state that on each debatable cost, our proposal

clearly benefits the lessees. Although they oppose several provisions

of the rule, these commenters recognize that the FERC Order 636

environment raises difficult issues for royalty valuation, and they

commend MMS for attempting a compromise proposal. In addition, one

State commenter added that with modifications, they generally supported

our efforts to amend the transportation allowance regulations.

In addition to the general comments, one tribe offered the

following comments regarding the economic analysis of the rule. They

believe that the Department has not complied with Department Manual,

Chapter 2, Part 512 and that the economic analysis shows a deficiency

of acting in the best economic interests of the tribe. They also

believe that we have not taken seriously our obligation to ensure

maximum revenue to the tribe. In the tribe's view, the statement that

this proposal meets MMS's goal of certainty, clarity, and consistency

is not an adequate basis to reduce Tribal royalties. The tribe asserts

that MMS's statement in the July 31, 1996, proposed rulemaking that the

rule will have a neutral or beneficial impact on Indian royalties is

devoid of any real economic demonstration. Finally, the tribe stated

that they are skeptical that the rule will have a neutral or beneficial

impact or that it will enhance MMS's ability to fulfill its trust

responsibility.

Six industry trade associations and three companies also offered

general comments. Every respondent believes that this rulemaking is

cumbersome and does not meet the goal of regulatory simplification or

streamlining. They believe the proposal:

Represents an extreme departure from current practice;

Exceeds MMS's statutory authority;

Is not supported by case law; and

Illegally extends the lessee's obligations.

Several industry trade associations commented that the proposal

will create heavy administrative expenses for producers to track gas

molecules to the burnertip. In today's complex marketplace, these

commenters believe the required tracking is impossible. One respondent

stated that pipelines are not consistent in billing and frequently do

not segregate costs, adding to the difficulty in compliance and

likelihood of being second guessed by us in later audits. One industry

trade association strongly urged us to withdraw this rule. If

necessary, it believes that changes can be addressed in a negotiated

rulemaking where all parties come to an equitable agreement. One

industry trade association stated that this proposal:

Fails to recognize the producer's lack of control over

fees; and

[[Page 65755]]

Penalizes and requires the producer to absorb all costs

and risks of marketing downstream.

One industry trade association believes that the burdens and

disincentives created by the rule dictate that we should allow

producers to make royalty payments in kind.

Response. One of the main purposes of this rulemaking is to clarify

the specific allowable and nonallowable costs of transportation. This

rule is a continuation of our commitment to assure that lessees deduct

only the actual, reasonable costs of transportation. We have carefully

considered each cost component and are not allowing any costs of

marketing as a deduction in the final rule.

Although one tribe believes that MMS did not comply with the

economic analysis required by the Departmental Manual, Chapter 2, Part

512, we believe that the changes under FERC Order 636 will enable us to

identify nonallowable costs of marketing. Prior to FERC Order 636,

lessees deducted some bundled marketing costs. Under the FERC Order 636

environment, these costs are now separately identified. Consequently,

this rulemaking limits the transportation allowance to the actual,

reasonable costs of transportation. Our rulemaking will have a neutral

or beneficial impact to the tribes, States, and Federal Treasury

because lessees will not be able to deduct these previously bundled

marketing costs.

We disagree with industry's statement that the Department does not

have the authority to promulgate this rule. MMS is mandated by law to

ensure that royalties are properly collected and distributed. See 30

U.S.C. 1701 et. seq. This responsibility includes providing clear

guidance to the oil and gas industry regarding which costs are

allowable transportation deductions and what are nonallowable marketing

costs. The comment that pipelines are not consistent in billing and

frequently do not segregate costs is contrary to FERC's requirement

that every pipeline make rate filings publicly available. Under FERC's

procedure, the pipeline must identify and justify the cost components.

Any shipper can analyze these filings and protest any inequitable

costs. Based on these reasons, MMS is publishing this rule as final.

MMS amends its regulations and deletes the existing sections

206.157(f) and 206.177(f) of 30 CFR part 206. (We retain the substance

of these paragraphs in later revised paragraphs.) Further, we

redesignate paragraph (g) of these sections as paragraph (h) and add

two new paragraphs. New paragraph (f) describes the types of costs we

will allow as part of a transportation allowance. A new paragraph (g)

lists those costs that we expressly disallow. Because some of the

nonallowable costs affect valuation, we also amend sections 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.

Specific Comments

Comments on Secs. 206.152, 206.172, 206.153, and 206.173 (relating

to paragraph (b)(1)(iv)) How to value over-delivered volumes under a

cash-out program.

We received comments from one State on the cash-out program. This

State agrees with our amendments to the valuation regulations for cash-

out programs.

Two industry trade associations and three companies commented on

the cash-out program. All industry commenters disagree with our cash-

out valuation proposal. They believe that we should accept the price

specified in the FERC-approved tariff for valuation purposes. Many

industry respondents stated that lessees cannot market production

downstream of the lease without being subject to cash-out provisions

under transportation contracts. These respondents also believe that:

Our proposal ignores that imbalances are inevitable; and

A cash-out provision is the best means to sell gas.

They also state that MMS is arbitrary and capricious if we do not

first determine that the lessee acted imprudently before disallowing

use of the cash-out provision outside the tolerance or using the

benchmarks to value gas. One company disagrees with our assertion that

volumes outside the tolerance (for over-delivery specified in the

transportation contract) are a violation of the duty to market for the

benefit of the lessee and lessor. This commenter believes that we

should only disallow the FERC-approved cash-out value when we determine

that the lessee is negligent.

Response. Pipelines developed tolerances in recognition of the fact

that nominations never match actuals, and receipts never match

deliveries. Because pipelines no longer own system supply gas to cover

imbalances, they must maintain strict controls over shippers to assure

system integrity. Pipelines developed the cash-out programs to penalize

those shippers outside the tolerances while allowing for minor

imbalances within tolerance. MMS also believes lessees must act

diligently in scheduling shipments on pipelines. In the final rule, we

retain the provision accepting the cash-out value within tolerance and

not accepting the value outside the tolerance. We also retain the

provision to value production under the benchmarks when the cash-out

provision results in an unreasonable value for royalty purposes. This

is consistent with the current valuation regulations requiring arm's-

length contracts to meet total consideration and reasonable value

criteria.

We amend paragraph (b)(1) of 30 CFR 206.152 and 206.172 (for

unprocessed gas), and 30 CFR 206.153 and 206.173 (for 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 exception adds new 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. We will not accept the penalty cash-out price as

royalty value.

The rule also provides that if we determine that the cash-out price

is unreasonably low, lessees must use the benchmarks to value the gas

instead of the cash-out price. Lessees should also note that for

production from Indian leases, other valuation provisions in the

regulations still apply; i.e., major portion and dual accounting.

Comments on Secs. 206.152(i), 206.172(i) (for unprocessed gas); and

206.153(i), and 206.173(i) (for processed gas).

One Indian tribe responded that all marketing costs must be borne

by the lessee and that the lessee must make every reasonable and

prudent effort to market production for the benefit of the lessor. All

other State and Indian respondents support this position but offered no

specific comments.

Five industry trade association groups and four companies submitted

responses regarding costs of placing production in marketable condition

and marketing costs. The following paragraphs summarize industry

specific responses.

General Comments. One industry trade association recommends

deleting the language ``and to market the gas for the mutual benefit of

the lessee and the lessor'' that we proposed adding to the existing

regulations. Several industry commenters stated that this marketing

language is beyond MMS's statutory authority and is bad public policy.

One industry commenter also stated the marketing language was a thinly

disguised attempt to increase revenue to

[[Page 65756]]

the government at the expense of lessees. Several industry commenters

believe that the marketing language will impose royalty on marketing

services long after production is saved, removed, or sold from the

lease and that the point of royalty valuation is moved from the lease

to the burnertip. These industry commenters also believe that even

though the producer sold marketable gas under an arm's-length contract

at the lease, lessees must trace gas all the way to the burnertip and

pay royalty on the value at a ``new'' marketplace. A few industry

commenters stated that we do not rely on a ``principled basis'' to

determine what will or will not be a marketing cost, and it will be

impossible for lessees to anticipate what downstream costs we will

disallow. Commenters assert that this will create a loss of certainty

for lessees. One company believes that the marketing language changes

value determination from the current policy of accepting arm's-length

gross proceeds to the highest-obtainable price anywhere from the lease

to the resale at the burnertip.

Duty to market/implied obligation to market. Almost every industry

trade association and company commenter stated that no obligation

exists to market production away from the lease. They asserted that

lessees are only obligated to market production at or near the lease.

In addition, they claim that even if this obligation to market

production is not new, the obligation to market production away from

the lease is new. All industry commenters believe that the rule creates

an unprecedented duty to market and imposes an elaborate new marketing

standard. These commenters also believe that the creation of this new

duty to market violates applicable statutes and lease terms. These

industry commenters also state that the implied obligation to market

for the mutual benefit of the lessee and the lessor never embodied the

obligation to market at no cost to the lessor. Several commenters

stated that this obligation is not implied simply because the agency

says so and the rule leaps from the realities of past precedent by

merely stating that the obligation to market production is implied.

Several commenters claim that the implied obligation to market is not

supported by Walter Oil and Gas, 111 IBLA 265 (1989) as cited by MMS.

Production in marketable condition. Several industry commenters

claimed that we erroneously link the obligation to place production in

marketable condition with the obligation to market that production. One

industry trade association stated that in Beartooth Oil and Gas Co. v.

Lujan, CV 92-99-BLG-RWA (D. Mont. Sept. 22, 1993, vacated and remanded)

(Beartooth), the court determined that the marketable condition rule

does not require the lessee to condition the gas so that it is suitable

for secondary or retail markets. They further state that a series of

markets exists between the lease and the burnertip but the lessee's

obligation to place production in marketable condition refers only to

the first market. Several industry commenters believe that the preamble

to the March 1, 1988, regulations clearly shows that our intent was not

to encompass any and all marketing costs but only those to place

production in marketable condition. Most commenters state that the

market for which production is conditioned is the market at or near the

lease. They further claim that the definition of marketable condition

in the March 1, 1988, rule focuses on gas that is sufficiently free

from impurities and not on marketing that gas.

Share in marketing costs. Three companies and two industry trade

associations claim that MMS is not entitled to a ``free ride'' on

marketing costs. They believe that if we benefit from marketing

activities then we should share in those costs. Two companies and one

industry trade association state that the proposal shows that we are

unwilling to share in costs to market but want to share in any higher

price gained when the lessee performs marketing. This is not for mutual

benefit of the lessee and lessor.

Breach of duty. Several industry trade associations and company

commenters offered the following comments on the lessees' duty to

market production. Because marketing costs are disallowed under the

rule, if lessees don't incur marketing costs, these commenters are

concerned that we will consider the lessee as breaching its duty to

market production. They are also concerned that MMS will question all

marketing decisions made by the lessee and make arbitrary

determinations that producers failed to obtain the highest price.

Response. We recognize that the obligation to place production in

marketable condition is legally distinct from the issue of marketing

the gas. However, the implied covenant of the lease dictates that

lessees must market production at no cost to the lessor. Both

principles are expressly stated in the March 1, 1988, gas regulations;

the definition for marketable condition at 30 CFR 206.151 discusses the

physical treatment of gas for placing gas in marketable condition and

30 CFR 202.151 states that no allowance will be made for other expenses

incidental to marketing. Based on these principles, MMS has

consistently applied the concept that the lessee must market gas at no

cost to the lessor and denied marketing costs as an allowable

deduction. See Arco Oil and Gas Co., 112 IBLA 8, 11 (1989); Walter Oil

and Gas Corp., 111 IBLA 260, 265 (1989). We have not changed the

principle of accepting gross proceeds under arm's-length contracts and

would not trace value beyond a true arm's-length transaction to the

burner tip, as commented. The rule simply clarifies which cost

components or other charges are deductible (transportation), and which

costs are not deductible (marketing). This is consistent with the

ruling in the Beartooth decision that addressed whether downstream

compression was the cost of placing production in marketable condition

or a transportation cost.

The final rule clarifies the principle that lessees cannot deduct

from royalty value the costs of marketing production from Federal and

Indian leases. The final rule adds specific language to paragraph (i)

of 30 CFR 206.152, 206.153, 206.172, and 206.173 to expressly state

lessees' obligation to incur all marketing costs. In all sections, we

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).'' We also add the

words ``or to market the gas'' at the end of the last sentence of that

paragraph to accomplish this objective. We believe 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 lessees

and lessors. We further believe this imposes no additional marketing

burden on the lessee than existing requirements.

Comments on Secs. 206.157(f)(1) and 206.177(f)(1) Firm demand

charges paid to pipelines.

One Indian tribal association, one State/Indian association, two

tribes, and two States offered comments on firm demand charges. One

tribe stated that if we allow firm demand charges, we must timely

review and audit the actual amount claimed. The tribe believes that

situations exist where lessees claim FERC-allowed costs, but lessees do

not actually pay these costs for transportation. The State commenter

agrees with our proposal allowing firm demand charges--limited to the

applicable rate per MMBtu multiplied by the actual volumes transported.

The State believes that it should not be liable for the additional

costs for two reasons.

[[Page 65757]]

First, the lessee has ways to mitigate costs for unused capacity.

Second, the lessor should not be liable for marketing mistakes caused

by overbuying capacity. One State/Indian association, one tribe, and

one State debated whether these charges are transportation charges or

marketing costs. However, these commenters agreed that MMS's position

is a reasonable compromise with the following two caveats. First, we

should review and adjust firm demand charges if they include otherwise

nondeductible costs or do not represent a lessee's reasonable actual

costs. Second, the lessee should reduce the claimed allowance if a

purchaser reimburses, directly or indirectly (through reservation

charges or fees) all or some of the producer's demand charges.

Three trade associations and four companies offered the following

comments on firm demand charges. All industry commenters believe that

we should allow the entire demand charge actually paid by the lessee.

One industry trade association and four companies believe that the

demand charge is a legitimate cost that often enables the gas to be

sold at a higher price. They believe the lessor should share in the

entire demand charge even if only a portion is used because the royalty

share benefits. Several industry commenters stated that the firm demand

charge is not allocated between used and unused capacity. They stated

that firm demand charges are consideration for transportation

irrespective of capacity used. Many of the industry commenters stated

that allowances should be reduced only when the lessee releases

capacity and receives a credit. Many commenters stated that factors

beyond the lessees' control can prevent them from using all reserved

capacity. By denying part of the firm demand, we imply lessees acted

imprudently and failed to market gas for the mutual benefit of the

lessee and the lessor. One company stated that we should allow the

demand/reservation charge because the charge is a transportation cost

that is indistinguishable from any other transportation service.

Response. Our valuation regulations require that we allow the

reasonable, actual costs of transportation. However, only the firm

demand rate per MMBtu is an actual cost of transportation. We do not

consider the amount paid for unused capacity as a transportation cost.

Therefore, in Secs. 206.157(f)(1) and 206.177(f)(1), we are allowing

firm demand charges--limited to the applicable rate per MMBtu

multiplied by the actual volumes transported--as allowable costs in

computing the transportation allowance.

Capacity release program. We also received comments on the capacity

release program. One Indian tribal association responded that they

agree with permitting allowances for those portions of both demand and

commodity charges that reflect the costs paid for gas actually shipped,

but not permitting allowances for the potential business costs

associated with purchases of surplus or unused capacity.

One company commenter would support including capacity release

gains and losses if all firm demand charges were allowed. Several

companies stated that there are no gains under the capacity release

program. One industry trade association and two companies recommend

rewriting the third sentence under firm demand charges to clearly state

that any gains or losses from the sale of unused firm charges are not

royalty bearing. These commenters also recommended clarifying the

fourth sentence which includes the term ``other reasons.'' These

respondents suggest using the term ``other refunds'' and clarifying the

sentence to state that any refunds received are not considered gross

proceeds if no firm demand charge was claimed on Form MMS-2014, Report

of Sales and Royalty Remittance (Form MMS-2014).

Response. We do not consider the gains and losses associated with

release of firm transportation as part of the actual cost of

transporting gas. In Secs. 206.157(f)(1) and 206.177(f)(1), lessees

with firm transportation may only claim the firm demand charge per

MMBtu multiplied by actual volumes transported, regardless of whether

they release part or all of their reserved capacity. If a lessee/

shipper acquires released capacity on a pipeline, we allow the cost of

buying that capacity to the extent that capacity is used. The final

rule provides that we will not participate in gains or losses

associated with released capacity.

We agree that the third sentence under firm demand charges should

be clarified and have replaced this sentence in the final rule with the

following sentence: ``The lessee also may not include any gains

associated with releasing firm capacity.''

Pipeline rate adjustments. The last issue under firm demand is

pipeline rate adjustments. We also requested comments on how to

simplify reporting for these adjustments. One Indian tribal association

agrees that any allowances taken that are later rebated are royalty

bearing. However, monitoring will be complicated if the refund or

rebate is credited against future charges.

Four industry trade associations and five companies responded to

pipeline rate adjustments. Several companies and industry trade

associations believe that the proposal is unfair because it disallows

deductions for penalties paid by the shipper but requires lessees to

pay their share of penalty monies refunded to other pipeline customers.

However, one company agreed that penalty refunds and rate case payments

should be subject to royalty. Individual companies responded that rate

case refunds don't segregate individual components into the allowable/

nonallowable items as defined by MMS. Therefore, differentiating

disallowed components will be unduly burdensome to the lessee. Another

company stated that the rule implies that penalty refunds are refunded

to the party who paid the penalty which may not be the case.

Most companies agree that monthly adjustments would be unduly

burdensome and that MMS should establish a distinct transaction code

and/or adjustment reason code for pipeline rate adjustments. Several

companies do not believe that a simplified reporting method for Indian

leases is possible because of major portion requirements. One company

suggested that lessees be allowed to assess a ``Royalty Administration

Fee'' to offset the costs associated with tracking all the exceptions

spelled out in this rule.

Response. Pipelines charge a specific rate for transportation

services. When FERC later requires pipelines to adjust these charges

through a pipeline rate refund, these adjustments reduce the

transportation allowance already taken by the lessee on the Form MMS-

2014. We considered several options for simplifying reporting, but

concluded that any form of rolled-up reporting would prohibit us from

determining royalty properly for both Federal onshore and offshore and

Indian lands. We use data reported on Form MMS-2014 from both Federal

and Indian leases to calculate major portion prices for Indian leases.

Rolling up transportation allowances will skew these major portion

calculations. We also use Form MMS-2014 data to monitor valuation

reporting and for settlement negotiation purposes. Therefore, in the

final rule, we have not modified reporting requirements for pipeline

rate adjustments. To reflect the FERC-modified transportation charge,

the lessee must adjust the allowance to account for the refund they

receive by reducing the allowance originally taken.

[[Page 65758]]

Comments on Secs. 206.157(f)(2) and 206.177(f)(2) Gas supply

realignment (GSR) costs.

One State/Indian association, two States and one tribe oppose MMS's

position that gas supply realignment (GSR) costs are transportation

costs. These respondents state that GSR costs are transitory and are

not related to a pipeline's transportation costs. Instead, these costs

relate only to money paid by pipelines to reform or terminate

contracts. They believe there is inherent inequity in industry's

position that industry is not required to pay royalties on contract

reformation payments but are entitled to deduct GSR costs when embedded

in a tariff.

One Indian tribal association questioned why we allow only that

portion of firm demand charges actually used, but allow recovery of GSR

costs paid through demand charges. They believe this negates the

initial objective of limiting firm demand to charges for actual volumes

transported. They also believe that the GSR cost ``carries'' the

royalty owner along on a myriad of business decisions by pipelines and

producers that have nothing to do with actual transportation of gas.

One State/Indian association, one State, and one tribe claim that

our position is inconsistent because contract reformation payments are

both royalty bearing and deductible. These commenters are opposed to

allowing GSR costs but as a compromise, suggest the following options:

If lessees receive contract settlement money and agree to

pay royalties on it, we could allow those lessees to deduct GSR costs;

If lessees do not receive contract settlement money, we

could allow those lessees to deduct GSR costs; and

If all lessees are required to pay royalties on contract

settlement money, we could allow GSR costs across the board.

One State commenter believes that allowing GSR costs violates the

gross proceeds rule.

All industry respondents agree that GSR costs should be deductible

and should not be tied to royalty consequences of gas contract

settlements or the outcome of any pending litigation. Several

commenters state that GSR costs are costs of transporting gas charged

to all pipeline customers.

Response. GSR costs stemmed specifically from FERC's regulatory

actions under FERC Order 636. FERC is mandated to recognize prudently

incurred costs in establishing just and reasonable rates for

transportation. We consider these costs as an actual cost of

transportation under the existing regulations and will allow GSR costs

as a transportation deduction in Secs. 206.157(f)(2) and 206.177(f)(2).

Comments on Secs. 206.157(f)(3) and 206.177(f)(3) Commodity

charges.

One Indian tribal association responded to this issue, stating that

they do not share MMS's assumption that demand and commodity charges

permit pipelines to recover only their fixed and variable costs. The

association claims that profit margins are built into both these

components as return on equity.

We received no comments from industry on this issue.

Response. The actual volumes transported on a firm transportation

contract are charged a firm transportation commodity charge in addition

to the reservation fee. All interruptible transportation rates are

billed at commodity charges only. These commodity charges represent the

pipeline's transportation-related variable costs. These are actual

costs incurred by lessees for transporting gas, and we will

specifically allow the commodity charge as a deduction in the final

rule. We recognize that valuation implications result from a lessee's

choice of securing firm versus interruptible services. 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. In

Secs. 206.157(f)(3) and 206.177(f)(3), we allow the commodity charges

paid to pipelines as allowable costs in computing the transportation

allowance.

Comments on Secs. 206.157(f)(4) and 206.177(f)(4) Wheeling costs.

One Indian tribal association stated that wheeling is an incidental

cost associated with shunting gas to a siding then back into the

transportation system. This respondent believes that these costs should

be treated like banking/parking fees and be disallowed. However, they

stated that if we allow wheeling, those costs should be limited to

actual reasonable costs.

We received no comments from industry on this issue.

Response. Wheeling is a physical transfer of gas from one pipeline

through the hub to either the same or another pipeline. This service is

directly related to transportation. We allow the costs of wheeling as a

transportation deduction in Secs. 206.157(f)(4) and 206.177(f)(4) of

the final rule.

Comments on Secs. 206.157(f)(5) and (6) and 206.177(f)(5) and (6)

Gas Research Institute (GRI) fees and Annual Charge Adjustment (ACA)

fees.

Two tribes, one Indian tribal association, and two State/Indian

associations oppose allowing Gas Research Institute (GRI)/Annual Charge

Adjustment (ACA) fees. All respondents believe that these fees are not

transportation-related costs.

We received no specific comments from industry.

Response. FERC requires member pipelines of GRI to charge customers

a fee for funding GRI programs. 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. FERC allows

pipelines to charge customers an ACA fee. This fee allows a pipeline to

recover its allocated share of FERC's operating expenses. Because such

fees are required transportation charges, we will allow GRI and ACA

fees under Secs. 206.157(f)(5) and (6), and 206.177(f)(5) and (6) of

the final rule. However, MMS is aware that GRI funding may become

completely voluntary. Therefore, we will allow GRI fees only as long as

they are mandatory fees in FERC-approved tariffs.

Comments on Secs. 206.157(f)(7) and 206.177(f)(7) Payments (either

volumetric or in value) for actual or theoretical losses.

One Indian tribal association, one State/Indian association, one

State, and one tribe believe that actual or theoretical losses are

nondeductible costs and should not be allowed even if they appear in a

tariff.

Four companies and three industry trade associations agree that

actual or theoretical losses should be allowed as a deduction in arm's-

length contracts and non-arm's-length transportation contracts if a

FERC or State regulatory agency-approved tariff includes these costs.

However, they believe that MMS's position on non-arm's-length

situations where no tariff exists is a discriminatory treatment of non-

arm's-length transportation situations. These respondents believe that

actual and theoretical losses should be allowed in all cases.

In addition to comments on actual or theoretical losses, five

industry respondents commented that MMS should clarify that gas supply

to the transporter for fuel (whether provided in kind or cash

reimbursement) will be an allowable transportation cost.

Response. We allow the cost of fuel as a deduction when it is used

for gas transportation. This policy has not changed under this rule. We

will continue to allow payments (either volumetric or in value) for

actual or

[[Page 65759]]

theoretical losses for arm's-length transportation arrangements and for

non-arm's-length transportation arrangements if based on a FERC or

State-regulatory approved tariff. However, we clarified the wording in

the new Secs. 206.157(f)(7) and 206.177(f)(7). There is no substantive

change from the existing rules.

Comments on Secs. 206.157(f)(8) and 206.177(f)(8) Temporary storage

services.

One Indian tribal association agreed that MMS should not allow

storage fees as a deduction. They believe that MMS should treat

temporary or short-term storage fees (commonly known as banking and

parking fees) as well as wheeling costs as nonallowable costs that are

incidental to marketing. The Indian tribal association believes that

MMS makes an exception to the gross proceeds rule regarding long-term

storage. This Indian tribal association also believes that if a lessee

stores gas for later sale, the lessee should pay an estimated royalty

and pay additional royalties due when production is actually sold.

Three industry trade associations and four companies disagree with

MMS's position that banking and parking are storage fees and not

deductible. They state that these fees are part of the transportation

process similar to wheeling, and we should allow these fees as a

deduction. Most respondents state that banking and parking are

necessary services to ensure balancing at market centers and hubs.

These commenters state that we have no justification to disallow these

fees, especially if the lessee is charged these fees in the same month

as a sale.

Response. After reviewing the comments, we agree that temporary

storage costs are different than long-term storage. Banking and parking

are short-term storage services that give pipelines and shippers

flexibility to avoid penalties related to imbalances. We agree with

industry, and we will change the final rule by adding new sections

206.157(f)(8) and 206.177(f)(8) titled ``Temporary storage services.''

These sections will allow short-term storage services as a

transportation deduction but will retain the sections 206.157(g)(1) and

206.177(g)(1) disallowing long-term storage. We define short-term

storage as temporary storage occurring at a hub or market center for a

duration of 30 days or less.

Comments on Secs. 206.157(f)(9) and 206.177(f)(9) Supplemental

costs for compression, dehydration, and treatment of gas.

One Indian tribal association, one State/Indian association, one

tribe, and one State believe these costs are part of the lessee's duty

to place production in marketable condition at no cost to the lessor.

They assert that they are not allowable no matter where they occur in

the transportation process. They further maintain that this provision

invites dispute and litigation over what is ``typical'' or ``unusual.''

One Indian/State association commented that the economic rationale for

permitting transportation allowances is that economic value is added by

transporting production away from the lease. That transportation cost

is then deducted from the enhanced value to determine value at the

lease. There is no indication that value is added by ``supplemental

services.'' Therefore, these costs should not be allowed.

Most of the industry commenters oppose the use of the word

``supplemental'' and recommend that it be replaced with the word

``other.'' These commenters stated that these services are an integral

part of the transportation process and not an activity to put gas in

marketable condition. They believe that once gas is in marketable

condition, all subsequent services should be deductible. Several

commenters state that compression, dehydration, and treatment of gas

are not supplemental to transportation, they are an integral part of

the transportation process.

A few industry trade associations and companies maintain that gas

entering mainline pipelines is already in marketable condition, and we

should allow deduction of all these costs. One company suggested that

we look at the intent of the services; are these costs to place gas in

marketable condition or for transportation? This company stated that

gas may be acceptable to the transporter without compression, however,

compression is necessary to offset line pressure in order to maintain

deliverability and effectively manage reservoirs. They assert that this

indicates that costs are due to transportation, not marketing

restraints.

Response. The supplemental services indicated in the rule are not

costs for 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. The costs addressed in the rule are costs that may

occur in unusual circumstances where the pipeline performs additional

compression, dehydration, or other treatment of gas for transportation

purposes. These costs exceed the services necessary to place production

in marketable condition. We allow charges for these supplemental

services as a deduction in the final rule by renumbering sections

206.157(f)(9) and 206.177(f)(9).

Comments on Secs. 206.157(g)(1) and 206.177(g)(1) Fees or costs

incurred for storage.

See comments under Secs. 206.157(f)(8) and 206.177(f)(8) above for

detailed discussion on short duration storage fees.

Response. The regulation at 30 CFR Sec. 202.150 (1996), 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. We consider 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. The final rule is consistent by not allowing any costs incurred

for storing production in a storage facility, whether on or off the

lease, for a duration of greater than 30 days.

Comments on Secs. 206.157(g)(2) and 206.177(g)(2) Aggregator/

marketer fees.

The State and Indian commenters support MMS's position of not

allowing aggregator/marketer fees as a transportation deduction. They

believe that aggregator/marketer fees are not transportation costs and

should be disallowed.

Four industry trade associations and three company respondents

objected to disallowing aggregator/marketer fees from the

transportation deduction. These respondents believe that lessees have

no duty to market production downstream of the lease and no obligation

to do so free of charge after production is placed in marketable

condition. Industry believes that aggregating production results in

enhanced value. Because MMS benefits from this enhanced value, industry

believes that we should also share in these costs.

One industry trade association stated that denying aggregator/

marketer fees will adversely affect independents because they do not

have the ability to aggregate large volumes of production and,

therefore, receive an enhanced value for gas.

Response. Aggregator/marketer fees are fees a producer pays to

another person or company including its affiliates to market its gas.

As previously discussed, the implied covenant to market the production

is the lessee's obligation and the lessor does not share in marketing

costs. The final rule in sections 206.157(g)(2) and 206.177(g)(2)

reflects this principle by not allowing aggregator/marketer fees as a

transportation deduction.

[[Page 65760]]

Comments on Secs. 206.157(g)(3)(i)-(iv) and 206.177(g)(3)(i)-(iv)

Penalties the lessee incurs as shipper.

One Indian tribal association and one State agree that penalties

for cash-out, scheduling, imbalance, and curtailment or operational

flow orders should be borne by the lessee. They believe that these

penalties are not associated with reasonable actual costs of

transportation. The State commenter believes that the lessee should

bear any unrecouped losses incurred by their own marketing mistakes.

Two industry trade associations and three companies responded to

the penalty provision. They agree that, within reasonable tolerances,

costs due to negligence or mismanagement by the lessee should not be

borne by the lessor. However, MMS should not disallow costs based on an

assumption of breach of duty to market. Instead, MMS should review

penalties on a case-by-case basis to determine if they were

unavoidable. These respondents believe that if penalties are

unavoidable, they should be deductible.

One company believes that MMS should share in all imbalance cash-

out penalties regardless of whether a portion of the imbalance exceeds

the pipeline tolerance level. This company believes that this proposal

is contrary to MMS's acceptance of arm's-length contract sales as the

basis for royalty value. They claim that imbalances are inevitable.

Response. We recognize that some imbalances occur. In cash-out

situations, we will allow lessees within tolerance to determine value

using that pipeline's specified rate. However, cash-out imbalances

outside the tolerance and scheduling, imbalance, and operational

penalties are costs incurred as a result of the lessee breaching its

duty to market the production to the mutual benefit of the lessee and

the lessor. These costs are marketing expenses the lessee must bear

because there are a variety of mitigating devices available to help the

lessee balance production and nominations. These devices include:

Swapping or transferring imbalances;

Establishing debit/credit accounts;

Using electronic bulletin boards to adjust for variations

between deliveries and nominations;

Using swing supply and flexible receipt point authority;

Entering into predetermined allocation agreements; or

Insisting upstream operators enter into operational

balancing agreements with downstream transporters.

In the final rule, we disallow as a transportation deduction:

Over-delivery cash-out penalties (Secs. 206.157(g)(3)(i)

and 206.177(g)(3)(i));

Scheduling penalties (Secs. 206.157(g)(3)(ii) and

206.177(g)(3)(ii));

Imbalance penalties (Secs. 206.157(g)(3)(iii) and

206.177(g)(3)(iii)); and

Operational penalties (Secs. 206.157(g)(3)(iv) and

206.177(g)(3)(iv)).

Comments on Secs. 206.157(g)(4) and 206.177(g)(4) Intra-hub

transfer fees.

We received no comments from any Indian tribes or associations or

States regarding intra-hub transfer fees.

Four industry trade associations and three companies offered the

following responses. Several industry respondents stated that these

fees track the ownership of the gas through the pipeline and MMS should

consider these fees as part of the transportation cost. One industry

trade association stated that if these fees are not deductible because

it is the duty of the lessee to perform these services at no cost to

the lessor, then MMS is implying that the small producer that doesn't

provide this service is breaching its duty. Most industry commenters

believe MMS should allow these fees because they are essential to

efficient management of transportation and are necessary to transport

gas through a hub. These commenters state that disallowing intra-hub

transfer fees unjustly punishes aggressive marketers seeking to get the

highest price.

Response. Intra-hub transfer fees are administrative costs and not

actual costs of gas transportation. We disallow these fees as part of

the transportation allowance in Secs. 206.157(g)(4) and 206.177(g)(4).

Comments on Secs. 206.157(g)(5) and 206.177(g)(5) Other

nonallowable costs.

One Indian tribal association emphatically agrees that marketing

costs are solely the province and duty of the producer. They stated

that no deductions against royalties should be permitted for marketing

costs. One State/Indian association, one tribe, and one State

particularly support MMS's proposal on other nonallowable costs.

Two industry trade associations and four companies responded to

this issue. All respondents believe that these costs, previously

bundled prior to FERC Order 636, should be allowed. Several respondents

claim that all these charges were allowable transportation costs for

decades and, while it may now be easier for us to examine pipeline

tariffs, we always had the ability to do so. These respondents believe

that disallowing such costs creates a new obligation. Several industry

commenters claim that MMS's concern about lessees relabelling or

restructuring nondeductible costs as transportation costs is unfounded

and unfair. Most commenters believe that this section will make it

difficult for the lessee to determine which costs are allowable and

nonallowable and prevents a fair examination of a particular fee's

acceptance as a transportation expense.

Response. MMS has never allowed marketing costs as deductions from

royalty value and maintains this position in the final rule. The fact

that these costs were embedded in a bundled charge does not mean that

we allow such charges. In the FERC Order 636 environment, component

costs previously aggregated are now separately identified in

transportation contracts. Some of these component costs are clearly

costs of marketing and we continue to consider these as nonallowable

costs under Secs. 206.157(g)(5) and 206.177(g)(5) as we have always

done.

III. Other Matters

Retroactive Effective Date

Six companies and six industry trade associations strongly disagree

with the retroactive effective date of May 18, 1992. Industry believes

that the rule is not merely a clarification but rather a substantive

rule that creates a whole new duty to market. They state that without

this rule we have no clear authority to collect royalties on several of

the issues under this rule and that it is a radical departure from

MMS's past practice and standards.

Industry maintains that we cannot legally apply the rule

retroactively for the following reasons:

We have not been delegated authority to retroactively

apply rules;

Retroactivity is against the Administrative Procedures

Act,

It is unlawful;

Retroactivity is against MMS's policy of prospective

rulemaking only; and

We are barred from action without specific Congressional

authority.

Finally, industry believes that they should not be penalized for

MMS's 4-year lack of instruction and that retroactivity will be an

excessive administrative burden. In addition, industry claims that data

may not exist for prior periods or cannot be recreated and that

retroactivity will require lessees to go to the burnertip to chase

charges such as intra-hub title transfer fees and aggregator/marketer

fees.

[[Page 65761]]

Response. Based on advice provided by the Department of the

Interior's Office of the Solicitor, we have determined that MMS does

not have express statutory authority to implement a retroactive

effective date for this rule. However, we disagree that this is a

substantive rule that changes or increases our existing authority and

policies. This rule merely clarifies and codifies long standing MMS

policies in terms of the revised FERC vernacular. Therefore, MMS is

making this final rule effective February 1, 1998.

Indian Leases

One tribe and one Indian tribal association strongly recommend that

separate transportation regulations should be adopted for Indian

leases. Because Federal and Indian lease terms differ, these commenters

believe that while excessive transportation deductions may be allowed

for Federal leases, such deductions should not be allowed for Indian

leases. They stated that this proposal does not recognize the narrower

permissibility of deductions under Indian lease terms and that we

should recognize the propriety of treating tribal leases different from

Federal leases. In addition, one Indian tribal association stated that

the Secretary's trust responsibility and duty to maximize revenues to

Indian mineral owners compel us to protect Indian royalties from being

subjected to transportation allowances that are not contemplated in the

lease.

We received no specific comments from industry respondents on the

subject of separate regulations for Indian gas.

Response. Although we recently separated existing valuation and

transportation regulations into individual sections for Federal and

Indian leases, the principles used to determine both value and

transportation were not changed. This rule is written to insert

pertinent individual paragraphs into the separate sections for Federal

and Indian leases. We will not publish a separate rule for Indian

leases. If we finalize new regulations for gas valuation on Indian

leases, this rulemaking may be superseded for Indian lands.

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.). Approximately 2,600

entities pay royalties to MMS on production from Federal and Indian

lands and the majority of these entities are small businesses because

they employ 500 or less employees. However, this rule will not

significantly impact these small businesses because this rule does not

add any reporting or valuation requirements. Likewise, this regulation

will not significantly or uniquely affect small governments because the

rule will not change the valuation principles embodied in existing

regulations. The sole purpose of this rule is to clarify which costs

are allowable transportation deductions or nonallowable marketing

costs.

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, ``Governmental

Actions and Interference with Constitutionally Protected Property

Rights.''

Executive Order 12866

This rule has been reviewed under Executive Order 12866 and is not

a significant regulatory action. MMS estimates that this rule may

result in a maximum of $3.37 million in additional royalties collected

annually. However, this maximum revenue impact is based on the

assumption that all tariffs for all Federal and Indian leases contained

a nonallowable deduction of $0.01/MMBtu for a fee such as a intra-hub

transfer fee.

Executive Order 12988

The Department has certified to OMB that this 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.

A mandate is a legal, statutory, or regulatory provision that imposes

an enforceable duty. A mandate does not include duties arising from

participation in a voluntary Federal program. MMS funds audits

performed by State and Indian auditors under voluntary cooperative

agreements. Since participation in these cooperative agreements is

voluntary and this rule will not require additional monies to perform

audits of FERC-approved tariffs, no Federal mandates will be imposed on

State, local, or tribal governments.

Paperwork Reduction Act

This rule has been examined under the Paperwork Reduction Act of

1995 and has been found to contain no new reporting or information

collection requirements.

National Environmental Policy Act of 1969

We have 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: December 3, 1997.

Bob Armstrong,

Assistant Secretary--Land and Minerals Management.

For the reasons set out in the preamble, MMS amends 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

[[Page 65762]]

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, 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. Where the value established under this

section is determined by a lessee's gross proceeds, that value will 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, paragraph (i), is revised 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. Where the value established under this section is

determined by a lessee's gross proceeds, that value will 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. 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.

Lessees may include, but are 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. You must limit the

allowable costs for the firm demand charges to the applicable rate per

MMBtu multiplied by the actual volumes transported. You may not include

any losses incurred for previously purchased but unused firm capacity.

You also may not include any gains associated with releasing firm

capacity. If you receive a payment or credit from the pipeline for

penalty refunds, rate case refunds, or other reasons, you must reduce

the firm demand charge claimed on the Form MMS-2014. You 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) Gas Research Institute (GRI) fees. 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. GRI

fees are allowable provided such fees are mandatory in FERC-approved

tariffs;

(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;

(8) Temporary storage services. This includes short duration

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. Temporary storage is limited to 30 days or less;

and

(9) 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.

Lessees may not 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 storing

production in a storage facility, whether on or off the lease, for more

than 30 days;

(2) Aggregator/marketer fees. This includes fees you pay to another

person (including your affiliates) to market your gas, including

purchasing and reselling the gas, or finding or

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maintaining a market for the gas production;

(3) Penalties you incur as shipper. These penalties include, but

are not limited to:

(i) Over-delivery cash-out penalties. This includes the difference

between the price the pipeline pays you for over-delivered volumes

outside the tolerances and the price you receive for over-delivered

volumes within the tolerances;

(ii) Scheduling penalties. This includes penalties you incur for

differences between daily volumes delivered into the pipeline and

volumes scheduled or nominated at a receipt or delivery point;

(iii) Imbalance penalties. This includes penalties you incur

(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. This includes fees you incur for

violation of the pipeline's curtailment or operational orders issued to

protect the operational integrity of the pipeline;

(4) Intra-hub transfer fees. These are fees you pay to hub

operators for administrative services (e.g., title transfer tracking)

necessary to account for the sale of gas within a hub; and

(5) Other nonallowable costs. Any cost you incur for services you

are required to provide at no cost to the lessor.

(h) Other transportation cost determinations. Use this section 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

7. 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