Federal Register / Vol. 62, No. 241 / Tuesday, December 16, 1997 / Rules and Regulations 65753

authority delegated to the Commissioner

of Food and Drugs and redelegated to

the Center for Veterinary Medicine, 21

CFR part 524 is amended as follows:

PART 524—OPHTHALMIC OR

TOPICAL DOSAGE FORM NEW

ANIMAL DRUGS

1. The authority citation for 21 CFR

part 524 continues to read as follows:

Authority: 21 U.S.C. 360b.

2. Section 524.770 is added to read as

follows:

§ 524.770 Doramectin.

(a) Specifications. Each milliliter of

solution contains 5 milligrams of

doramectin.

(b) Sponsor. See 000069 in

§ 510.600(c) of this chapter.

(c) Related tolerances. See § 556.225

of this chapter.

(d) Conditions of use—Cattle—(1)

Amount. 5 milligrams per 10 kilograms

(5 milligrams per 22 pounds).

(2) Indications for use. For treatment

and control of infections of

gastrointestinal roundworms,

lungworms, eyeworms, grubs, biting and

sucking lice, and mange mites, and to

control infections and to protect from

reinfection with Cooperia oncophora

and Dictyocaulus viviparus for 21 days,

and Ostertagia ostertagia, C. punctata,

and Oesophagostomum radiatum for 28

days after treatment.

(3) Limitations. Administer as a single

dose. Do not slaughter cattle within 45

days of latest treatment. Not for use in

female dairy cattle 20 months of age or

older. Do not use in calves to be

processed for veal. Consult your

veterinarian for assistance in the

diagnosis, treatment, and control of

parasitism.

Dated: October 22, 1997.

Stephen F. Sundlof,

Director, Center for Veterinary Medicine.

[FR Doc. 97–32807 Filed 12–15–97; 8:45 am]

BILLING CODE 4160–01–F

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.

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

DavidlGuzy@mms.gov.

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 DavidlGuzy@mms.gov.

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
65754 Federal Register / Vol. 62, No. 241 / Tuesday, December 16, 1997 / Rules and Regulations

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 nonarm’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 FERCapproved 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
Federal Register / Vol. 62, No. 241 / Tuesday, December 16, 1997 / Rules and Regulations 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 §§ 206.152, 206.172,

206.153, and 206.173 (relating to

paragraph (b)(1)(iv)) How to value overdelivered 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 §§ 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
65756 Federal Register / Vol. 62, No. 241 / Tuesday, December 16, 1997 / Rules and Regulations

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’slength 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 §§ 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.
Federal Register / Vol. 62, No. 241 / Tuesday, December 16, 1997 / Rules and Regulations 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 §§ 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

§§ 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.
65758 Federal Register / Vol. 62, No. 241 / Tuesday, December 16, 1997 / Rules and Regulations

Comments on §§ 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

§§ 206.157(f)(2) and 206.177(f)(2).

Comments on §§ 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 §§ 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 §§ 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 §§ 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 §§ 206.157(f)(4) and

206.177(f)(4) of the final rule.

Comments on §§ 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 §§ 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 §§ 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
Federal Register / Vol. 62, No. 241 / Tuesday, December 16, 1997 / Rules and Regulations 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 §§ 206.157(f)(7) and

206.177(f)(7). There is no substantive

change from the existing rules.

Comments on §§ 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 longterm 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 §§ 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 §§ 206.157(g)(1) and

206.177(g)(1) Fees or costs incurred for

storage.

See comments under §§ 206.157(f)(8)

and 206.177(f)(8) above for detailed

discussion on short duration storage

fees.

Response. The regulation at 30 CFR

§ 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 §§ 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.
65760 Federal Register / Vol. 62, No. 241 / Tuesday, December 16, 1997 / Rules and Regulations

Comments on §§ 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, cashout 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

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

• Scheduling penalties

(§§ 206.157(g)(3)(ii) and

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

• Imbalance penalties

(§§ 206.157(g)(3)(iii) and

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

• Operational penalties

(§§ 206.157(g)(3)(iv) and

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

Comments on §§ 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 §§ 206.157(g)(4) and

206.177(g)(4).

Comments on §§ 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

§§ 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.
Federal Register / Vol. 62, No. 241 / Tuesday, December 16, 1997 / Rules and Regulations 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:

§ 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 overdelivered volumes, the royalty value is

the price the pipeline is required to pay
65762 Federal Register / Vol. 62, No. 241 / Tuesday, December 16, 1997 / Rules and Regulations

for volumes within the tolerances for

over-delivery specified in the

transportation contract. Use the same

value for volumes that exceed the overdelivery 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:

§ 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:

§ 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 overdelivered 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 overdelivery 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:

§ 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 § 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:

§ 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 nonarm’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 §§ 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 nonarm’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
Federal Register / Vol. 62, No. 241 / Tuesday, December 16, 1997 / Rules and Regulations 65763

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 overdelivered 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:

§ 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 overdelivered 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 overdelivery 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.

* * * * *

8. Section 206.172, paragraph (i), is

revised to read as follows:

§ 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.

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.

* * * * *

9. 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:

§ 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 overdelivered 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 overdelivery 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 206.173, paragraph (i), is

revised to read as follows:

§ 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. 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.

* * * * *

11. In § 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:

§ 206.177 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
65764 Federal Register / Vol. 62, No. 241 / Tuesday, December 16, 1997 / Rules and Regulations

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 nonarm’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 §§ 206.172(i) and 206.173(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 nonarm’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

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 overdelivered 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.

[FR Doc. 97–32802 Filed 12–15–97; 8:45 am]

BILLING CODE 4310–MR–P

FEDERAL COMMUNICATIONS

COMMISSION

47 CFR Part 73

[MM Docket No. 97–162; RM–9112]

Radio Broadcasting Services;

Hutchinson, KS

AGENCY: Federal Communications

Commission.

ACTION: Final rule.

SUMMARY: The Commission, at the

request of Gary L. Violet, allots Channel

240A at Hutchinson, Kansas. See 62 FR

41016, July 31,1997. Channel 240A can

be allotted to Hutchinson in compliance

with the Commission’s minimum

distance separation requirements

without the imposition of a site

restriction. The coordinates for Channel

240A at Hutchinson are 38–04–54 NL

and 97–55–42 WL. With this action, this

proceeding is terminated.

DATES: Effective January 20, 1998. A

filing window for Channel 240A at

Hutchinson, Kansas, will not be opened

at this time. Instead, the issue of

opening a filing window for this

channel will be addressed by the

Commission in a subsequent order.

FOR FURTHER INFORMATION CONTACT: Pam

Blumenthal, Mass Media Bureau, (202)

418–2180.

SUPPLEMENTARY INFORMATION: This is a

synopsis of the Commission’s Report

and Order, MM Docket No. 97–162,

adopted November 5, 1997, and released

December 5, 1997. The full text of this

Commission decision is available for

inspection and copying during normal

business hours in the FCC Reference

Center (Room 239), 1919 M Street, NW,

Washington, DC. The complete text of

this decision may also be purchased

from the Commission’s copy contractor,

ITS, Inc., (202) 857–3800, 1231 20th

Street, NW, Washington, DC 20036.

List of Subjects in 47 CFR Part 73

Radio broadcasting.

Part 73 of title 47 of the Code of

Federal Regulations is amended as

follows:

PART 73—[AMENDED]

1. The authority citation for Part 73

continues to read as follows:

Authority: 47 U.S.C. 154, 303, 334, 336.

§ 73.202 [Amended]

2. Section 73.202(b), the Table of FM

Allotments under Kansas, is amended

by adding Channel 240A at Hutchinson.

Federal Communications Commission.

John A. Karousos,

Chief, Allocations Branch, Policy and Rules

Division, Mass Media Bureau.

[FR Doc. 97–32702 Filed 12–15–97; 8:45 am]

BILLING CODE 6712–01–F

FEDERAL COMMUNICATIONS

COMMISSION

47 CFR Part 73

[MM Docket No. 97–32; RM–8931; RM–9065]

Radio Broadcasting Services; Calico

Rock and Leslie, AR

AGENCY: Federal Communications

Commission.

ACTION: Final rule.