97-32802. Amendments to Transportation Allowance Regulations for Federal and Indian Leases to Specify Allowable Costs and Related Amendments To Gas Valuation Regulations

[Federal Register Volume 62, Number 241 (Tuesday, December 16, 1997)]
[Rules and Regulations]
[Pages 65753-65764]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 97-32802]


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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 [phone], e-Mail [e-mail].

FOR FURTHER INFORMATION CONTACT: David S. Guzy, Chief, Rules and 
Publications Staff, Royalty Management Program, Minerals Management 
Service, phone [phone], FAX [phone], e-Mail 
[e-mail].

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

[[Page 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 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 
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.
* * * * *
    8. Section 206.172, paragraph (i), is revised to read as follows:


Sec. 206.172  Valuation standards--unprocessed gas.

* * * * *
    (i) The lessee must place gas in marketable condition and market 
the gas for the mutual benefit of the lessee and the lessor at no cost 
to the Indian lessor. 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:


Sec. 206.173  Valuation standards-processed gas.

* * * * *
    (b)(1)(i) The value of residue gas or any gas plant product sold 
under an arm's-length contract is the gross proceeds accruing to the 
lessee, except as provided in paragraphs (b)(1)(ii), (iii), and (iv) of 
this section.
* * * * *
    (iv) How to value over-delivered volumes under a cash-out program. 
This paragraph applies to situations where a pipeline purchases gas 
from a lessee according to a cash-out program under a transportation 
contract. For all over-delivered volumes, the royalty value is the 
price the pipeline is required to pay for volumes within the tolerances 
for over-delivery specified in the transportation contract. Use the 
same value for volumes that exceed the over-delivery tolerances even if 
those volumes are subject to a lower price under the transportation 
contract. However, if MMS determines that the price specified in the 
transportation contract for over-delivered volumes is unreasonably low, 
the lessee must value all over-delivered volumes under paragraph (c)(2) 
or (c)(3) of this section.
* * * * *
    10. Section 206.173, paragraph (i), is revised to read as follows:


Sec. 206.173  Valuation standards--processed gas.

* * * * *
    (i) The lessee must place residue gas and gas plant products in 
marketable condition and market the residue gas and gas plant products 
for the mutual benefit of the lessee and the lessor at no cost to the 
Indian lessor. 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 Sec. 206.177, paragraph (f) is removed; paragraph (g) is 
redesignated as paragraph (h) and revised; and new paragraphs (f) and 
(g) are added to read as follows:


Sec. 206.177  Determination of transportation allowances.

* * * * *
    (f) Allowable costs in determining transportation allowances. 
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

[[Page 65764]]

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. 206.172(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 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 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.

[FR Doc. 97-32802 Filed 12-15-97; 8:45 am]
BILLING CODE 4310-MR-P