[Federal Register Volume 69, Number 141 (Friday, July 23, 2004)]
[Proposed Rules]
[Pages 43944-43955]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 04-16725]


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DEPARTMENT OF THE INTERIOR

Minerals Management Service

30 CFR Part 206

RIN 1010-AD05


Federal Gas Valuation

AGENCY: Minerals Management Service (MMS), Interior.

[[Page 43945]]


ACTION: Proposed rule.

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SUMMARY: The MMS is proposing to amend the existing regulations 
governing the valuation of gas for royalty purposes produced from 
Federal leases. The current regulations became effective on March 1, 
1988, and were amended in relevant respects in 1996 and 1998.
    In continuing to evaluate the effectiveness and efficiency of its 
rules, MMS has identified certain issues that warrant proposal and 
public comment. These issues primarily concern calculation of 
transportation costs (including the allowed rate of return in 
calculation of actual transportation costs in non-arm's-length 
transportation arrangements, and further specific itemization of 
allowable and non-allowable costs), revision or simplification of 
certain provisions, and changes necessitated by judicial decisions in 
subsequent litigation. The MMS is proposing some changes to be 
consistent with analogous provisions of the recently-amended Federal 
crude oil valuation rule.

DATES: Comments must be submitted on or before September 21, 2004.

ADDRESSES: Address your comments, suggestions, or objections regarding 
this proposed rule to:
    By regular U.S. Mail. Minerals Management Service, Minerals Revenue 
Management, Chief of Staff, P.O. Box 25165, MS 302B2, Denver, Colorado 
80225-0165; or
    By overnight mail or courier. Minerals Management Service, Minerals 
Revenue Management, Building 85, Room A-614, Denver Federal Center, 
Denver, Colorado 80225; or
    By e-mail. [email protected]. Please submit Internet comments as 
an ASCII file and avoid the use of special characters and any form of 
encryption. Also, please include ``Attn: RIN 1010-AD05'' and your name 
and return address in your Internet message. If you do not receive a 
confirmation that we have received your Internet message, call the 
contact person listed below.

FOR FURTHER INFORMATION CONTACT: Sharron L. Gebhardt, Lead Regulatory 
Specialist, Minerals Revenue Management, MMS, telephone (303) 231-3211, 
fax (303) 231-3781, or e-mail [email protected]. The principal 
authors of this rule are Geoffrey Heath of the Office of the Solicitor 
and Larry E. Cobb and Susan Lupinski of Minerals Revenue Management, 
MMS, Department of the Interior.

SUPPLEMENTARY INFORMATION:

I. Background

    The MMS is proposing to amend the existing regulations at 30 CFR 
206.150 et seq. governing the valuation of gas for royalty purposes 
produced from Federal leases. The MMS conducted four public workshops 
from April 23 through May 1, 2003, in Denver, Colorado; Albuquerque, 
New Mexico; Houston, Texas; and Washington, DC. At those workshops, MMS 
asked for discussion regarding, among other things, royalty treatment 
of non-arm's-length dispositions (including possible use of New York 
Mercantile Exchange (NYMEX) prices or spot market index prices in place 
of the current ``benchmarks'' for valuing gas not sold under arm's-
length contracts), greater specificity regarding allowable 
transportation costs, the rate of return used in calculating actual 
transportation costs, and the royalty effect of sales under joint 
operating agreements. After considering the input from these workshops, 
MMS is proposing these amendments in an effort to improve the current 
rule. The amendments proposed do not alter the basic structure or 
underlying principles of the current rule.

II. Explanation of Proposed Amendments

    Comments at the workshops on major valuation issues--such as using 
spot market index prices or NYMEX prices to value gas not sold under 
arm's-length contracts, treatment of affiliate resales, and joint 
operating agreements--were in some cases somewhat sparse, and in other 
cases quite polarized. Due to the disparity of comments and concerns 
expressed at the workshops about publicly available spot market prices 
for natural gas, we have decided that we are not ready to propose new 
rules on some of these issues at this time. The MMS is continuing to 
evaluate these issues but will not address them in this proposed rule. 
For future consideration, we request current public comment on (1) 
whether publicly available spot market prices for natural gas are 
reliable and representative of market value of natural gas and should 
be considered by MMS as a means of valuing natural gas production that 
is not sold at arm's-length and, if so, (2) how should these spot 
market prices be adjusted for location differences between the index 
pricing point and the lease.
    On other matters, however, comments indicated that proposed changes 
were appropriate. For example, MMS adopted a final rule amending the 
Federal crude oil royalty valuation regulations that became effective 
in June 2000. 65 FR 10422. Some of these proposed changes for the gas 
valuation rules would conform to what MMS adopted for crude oil in June 
2000. In addition, there are certain issues, on which MMS did not 
specifically request comments at the workshops, for which proposed 
changes are appropriate, particularly in light of both recent judicial 
decisions and the recently-amended Federal crude oil valuation rule (69 
FR 24959, May 5, 2004). This proposal addresses issues in the latter 
categories.
    The explanation of the proposed changes will proceed in order 
according to the section number in the current rule (30 CFR part 206 
subpart D) for which amendment(s) are proposed.

A. Section 206.150--Purpose and Scope

    The MMS is proposing to amend Sec. 206.150(b) by separating it into 
subparagraphs and adding a new subparagraph (3). The new subparagraph 
(3) would provide that if a written agreement between the lessee and 
the MMS Director establishes a production valuation method for any 
lease that MMS expects at least would approximate the value otherwise 
established under this subpart, the written agreement will govern to 
the extent of any inconsistency with the regulations. This provision is 
intended to provide flexibility to both MMS and the lessee in those few 
unusual circumstances where a separate written agreement is reached, 
while at the same time maintaining the integrity of the regulations. As 
noted, any such agreement also must at least approximate the royalty 
value for the production that would apply under these regulations.
    This proposed amendment is identical to 30 CFR 206.100(d) in the 
Federal crude oil valuation rule amended in June 2000. The MMS has used 
the provision in the crude oil regulation to address a few unexpectedly 
difficult royalty valuation problems. The MMS believes that if this 
option is useful to lessees and the MMS Director in the context of 
crude oil royalty valuation, it likewise should be available for gas 
valuation.

B. Section 206.151--Definitions

    The MMS proposes to add a definition of the term ``affiliate'' and 
revise the definition of the term ``arm's-length contract'' to be 
identical to the June 2000 Federal crude oil valuation rule and to 
conform the gas valuation rule with the D.C. Circuit's holding in 
National Mining Association v. Department of the Interior, 177 F.3d 1 
(D.C. Cir. 1999). As in the 2000 Federal crude oil rule, MMS is 
proposing to

[[Page 43946]]

define the term ``affiliate'' separately from the term ``arm's-length 
contract.'' We believe this clarifies and simplifies the definitions 
and should promote better understanding of both ``arm's-length 
contract'' and ``affiliate.'' For a full explanation of the reasons for 
this proposed change to the definitions, see the discussion in the 
preamble to the June 2000 final crude oil valuation rule at 65 FR 
14022, at 14039-14040 (Mar. 15, 2000).
    The MMS also proposes to revise the definition of ``transportation 
allowance,'' which is part of the term ``allowance.'' In the 1988 rule, 
the term ``transportation allowance'' (within the term ``allowance'') 
was defined as follows:

    Transportation allowance means an allowance for the reasonable, 
actual costs incurred by the lessee for moving unprocessed gas, 
residue gas, or gas plant products to a point of sale or point of 
delivery off the lease, unit area, communitized area, or away from a 
processing plant, excluding gathering, or an approved or MMS-
initially accepted deduction for costs of such transportation, 
determined pursuant to this subpart.

30 CFR 206.151 (1988-1995). In 1996, the definition was changed to the 
current definition, which reads as follows:

    Transportation allowance means an allowance for the cost of 
moving royalty bearing substances (identifiable, measurable oil and 
gas, including gas that is not in need of initial separation) from 
the point at which it is first identifiable and measurable to the 
sales point or other point where value is established under this 
subpart.

30 CFR 206.151 (1996-2003) (promulgated at 61 FR 5448, at 5464 (Feb. 
12, 1996)). The principal purpose of the 1996 rulemaking was to 
eliminate various form filing requirements in connection with 
transportation and processing allowances for Federal leases, and, in 
that connection, to separate the valuation rules applicable to Indian 
leases from the rules applicable to Federal leases. 61 FR at 5448. The 
only statement in the preamble to the 1996 rule regarding the 
definition of ``allowance'' was as follows:

    Allowance. We changed the definition to remove any implication 
of a forms filing requirement, or of having to seek MMS approval 
prior to claiming an allowance on Form MMS-2014.

61 FR at 5451. While this reason may be relevant to eliminating the 
words ``or an approved or MMS-initially accepted deduction for costs of 
such transportation'' in the 1988 rule's definition, it has no apparent 
relevance to the other changes in the wording of the definition, for 
which no explanation at all was given in the preamble.
    Indeed, the proposed rule, published on August 7, 1995, at 60 FR at 
40127, did not even propose a change to the definition of ``allowance'' 
or of ``transportation allowance'' at all. Nor did it ask for comments 
on the allowance definitions.
    The only reference to the language promulgated in 1996 in any 
previous Federal Register notice was in a November 6, 1995 proposed 
rule (60 FR at 56007). That proposal grew out of discussions with 
States and industry regarding possible major changes in gas valuation 
methodology. The November 1995 proposal was not related to the changes 
in the allowance form filing requirements, and was not part of the 
origins of the February 1996 final rule. The November 1995 proposed 
rule included a number of interrelated changes. One of them was a 
change in the definition of ``transportation allowance'' that was 
identical to the language found in the February 1996 final rule on 
allowance form filing requirements. The November 1995 proposed rule was 
never finalized, and MMS formally withdrew it on April 22, 1997 (62 FR 
at 19536).
    There is no explanation in the preamble to the February 1996 final 
rulemaking of why or how the definition from the unrelated November 
1995 proposal found its way into the February 1996 final rule on 
allowance form filing requirements. There is no indication in any of 
the Federal Register notices in connection with the February 1996 final 
rulemaking of any intent to change the definition of ``transportation 
allowance.'' Nor did the February 1996 final rule include any other 
provisions from the unrelated November 1995 proposal, including 
provisions that were related to the definition of ``transportation 
allowance'' in that proposal. The 1996 change in the wording of the 
definition appears to have been an inadvertent clerical mistake. In 
practice, both industry and MMS have continued to conduct business 
since 1996 on the basis that the substantive definition of 
``transportation allowance'' has remained unchanged. That practice and 
course of conduct correctly reflect the underlying intent of the 
existing rules.
    To correct any ambiguity, MMS is proposing to amend the definition 
of ``transportation allowance'' to be consistent with the June 2000 
Federal crude oil valuation rule, with necessary changes in wording to 
apply it in the gas context. The proposed definition reads as follows:

    Transportation allowance means an allowance for the reasonable, 
actual costs of moving unprocessed gas, residue gas, or gas plant 
products to a point of sale or delivery off the lease, unit area, or 
communitized area, or away from a processing plant. The 
transportation allowance does not include gathering costs.

This proposed change also returns the definition to being substantively 
the same as the original 1988 rule's definition.
    Finally, MMS proposes to add the word ``actual'' before the word 
``costs'' in the definition of ``processing allowance.'' The February 
1996 final rule on allowance form filing requirements deleted that word 
with no explanation. The proposed change restores the pre-1996 wording 
and makes the wording of this definition consistent with wording of 
other allowance definitions. MMS does not intend to change the meaning 
of the term ``processing allowance'' in any respect.

C. Section 206.157--Determination of Transportation Allowances

    The MMS is proposing a number of changes and technical corrections 
to this section. First, MMS proposes to change the allowed rate of 
return in Sec.  206.157(b)(2)(v) used in calculating transportation 
costs for non-arm's-length transportation arrangements. Under Sec.  
206.157(b)(2), the lessee has a choice of two methods for calculating 
transportation costs. The first method allows the lessee to use its 
operating and maintenance expenses, overhead, depreciation, and a rate 
of return on its undepreciated capital investment. Under the second 
method, the lessee may use its operating and maintenance expenses, 
overhead, and a rate of return on its initial investment. The MMS 
proposes to change the allowable rate of return used in both of these 
calculation methods.
    The rate of return in the current Sec.  206.157(b)(2) is the 
industrial rate associated with the Standard and Poor's BBB rating. The 
MMS believed that this rate represented an intermediate rate fairly 
reflective of the industry's overall cost of money necessary to 
construct transportation facilities (principally through debt 
financing). The MMS proposes to increase that rate to 1.3 times the 
rate associated with the BBB rating.
    The reason for proposing this rate is a recent MMS, Offshore 
Minerals Management, Economics Division study of gas pipeline costs of 
capital. The study examined Energy Information Administration (EIA) 
published returns on investment for 2000-2001 for firms

[[Page 43947]]

engaged in the pipeline business, which is one indicator of the cost of 
capital. The MMS study also examined cost of capital data for gas 
pipelines and distributors published by Ibbotson for the first quarter 
of 2003. The EIA data indicated that the average rate of return for 
firms in the pipeline business approximated the BBB rate, and that most 
pipelines have a BBB rating for their debt capital. The Ibbotson data 
showed a cost of capital range for gas pipelines and distributors 
between 1.1 times BBB and 1.5 times BBB. (The MMS study also discusses 
a recent American Petroleum Institute (API) research paper that took 
the approach that a weighted average cost of debt and equity represents 
the true cost of capital for non-independent pipelines. The API paper 
finds a ratio of weighted average cost of capital to the BBB bond rate 
of between 1.6 and 1.8. However, the API paper appears to be based on 
the weighted average cost of capital for the oil production industry as 
opposed to the gas pipeline industry.)
    Based on the assumptions underlying the Ibbotson range of findings 
that MMS's study believed were most accurate, it found 1.3 times BBB to 
be the most appropriate. The MMS therefore is proposing this rate. This 
is also the rate that MMS adopted in its recently-amended Federal crude 
oil valuation rule (69 FR 24959, May 5, 2004). The MMS seeks comments 
regarding the proper rate of return and supporting data and analysis.
    The MMS recognizes that some industry commenters in three of the 
workshops recommended that the same rate of return that applies in non-
arm's-length transportation cost calculations also should apply in non-
arm's-length processing cost calculations. The processing cost 
regulations at 30 CFR 206.159(b)(2)(v) also allow for a rate of return 
equal to the Standard & Poor's BBB bond rate. However, MMS is not 
proposing a change in the rate of return for non-arm's-length 
processing cost calculations at this time because the MMS study did not 
extend to gas processing plant costs. The MMS welcomes comments, data, 
and analysis on that issue. If MMS obtains sufficient information and 
data through the comment process to support a change, it may change the 
rate of return used in non-arm's-length processing cost calculations in 
the final rule.
    The MMS proposes to rewrite Sec.  206.157(b)(5). This provision 
allows lessees to apply for an exception to the requirement to 
calculate actual costs in non-arm's-length transportation situations if 
the lessee has a tariff approved by the Federal Energy Regulatory 
Commission (FERC) or a State regulatory agency. The provision as 
currently written then adds a number of conditions that are difficult 
to interpret. The MMS's experience has been that these conditions have 
been difficult to apply and are burdensome on the lessees. (For 
example, the lessee must calculate actual costs before it can claim the 
exception from the requirement to calculate actual costs under some 
circumstances (i.e., if there are no arm's-length transportation 
charges to use for comparison, and if no FERC or state regulatory 
agency cost analysis exists, and if FERC or the state regulatory agency 
declines to investigate after a timely MMS objection).) The underlying 
concept that the current provision is meant to embody is that if a 
regulatory agency has either adjudicated a particular tariff for a 
transportation system (to resolve an objection to the tariff as filed) 
or has analyzed the tariff (if there is no objection filed) and found 
it to be a just and reasonable rate, the lessee should be able to use 
it as the basis for its transportation allowance as long as the tariff 
rate is still consistent with actual market conditions. The current 
wording, however, does not necessarily accomplish this objective.
    The MMS proposes to simplify Sec. 206.157(b)(5) by rewriting it as 
follows:

    You may apply for an exception from the requirement to compute 
actual costs under paragraphs (b)(1) through (b)(4) of this section.
    (i) The MMS will grant the exception if (A) the transportation 
system has a tariff approved by the Federal Energy Regulatory 
Commission (FERC) or a state regulatory agency that FERC or the 
state regulatory agency has either adjudicated or specifically 
analyzed, and (B) third parties are actually paying prices under the 
tariff to transport gas on the system under arm's-length 
transportation contracts.
    (ii) If MMS approves the exception, you must calculate your 
transportation allowance for each production month based on the 
volume-weighted average of the rates paid by the third parties under 
arm's-length transportation contracts during that production month. 
If during any production month there are no prices paid under the 
tariff by third parties to transport gas on the system under arm's-
length transportation contracts, you may use the volume-weighted 
average of the rates paid by third parties under arm's-length 
transportation contracts in the most recent preceding production 
month in which third parties paid such rates, for up to two 
successive production months.
    (iii) You may use the exception under this paragraph if the 
tariff remains in effect and no more than two production months have 
elapsed since third parties paid prices under the tariff to 
transport gas on the system under arm's-length transportation 
contracts.

Under this proposal, if a transportation system with which the lessee 
is affiliated has an approved tariff that has been either adjudicated 
or specifically analyzed, and if there are currently arm's-length 
shippers on that system, then the lessee would not have to calculate 
actual costs. But the allowance would not necessarily be the maximum 
tariff rate. Instead, it would be the volume-weighted average of the 
arm's-length rates charged to the non-affiliated shippers. This would 
avoid the potential for the lessee to claim a transportation allowance 
that exceeds the market transportation rates actually charged to arm's-
length shippers.
    The proposed provision also covers situations (which MMS 
anticipates would be rare) in which there is a short gap of one or two 
production months in which there are no arm's-length prices paid by 
third parties to transport gas on the system. Such a situation might 
arise if there were very few arm's-length third-party shippers, and the 
third party shippers temporarily were without contracts to sell their 
gas. In that event, the proposed rule would allow the lessee to use the 
volume-weighted average of the rates paid by third parties under arm's-
length transportation contracts in the most recent preceding production 
month in which third parties paid such rates, for up to two successive 
production months, during the ``gap'' period. If there are no arm's-
length transportation rates charged to unaffiliated shippers for more 
than two successive production months, the lessee would not be able to 
use the exception and would have to calculate actual costs. Similarly, 
the lessee would have to calculate actual costs if the tariff expires.
    Further, the mere filing of a tariff with FERC or a State 
regulatory agency is not sufficient for a lessee to invoke the 
exception. The tariff must either be adjudicated, or, if no party files 
an objection to a filed tariff, it must be specifically analyzed by 
either FERC or the State regulatory agency.
    The MMS also proposes to amend Sec.  206.157(c) in several 
respects. First, the proposal would eliminate the requirement that the 
lessee report its transportation allowance using a separate line entry 
on the Form MMS-2014. That requirement is no longer relevant because 
the Form MMS-2014 has been revised. While the transportation allowance 
is still reported in a discrete field, it is not strictly on a separate 
line from associated sales transaction data. The proposal would revise 
the regulation accordingly.

[[Page 43948]]

    Second, the wording of the proposed new paragraph (c) would make it 
consistent with the analogous provisions of the June 2000 Federal crude 
oil valuation rule at Sec. Sec.  206.114 and 206.115.
    Third, the proposed rule would add new paragraphs (c)(1)(iii) and 
(c)(2)(v) to expressly clarify that allowances that were in effect when 
the 1988 valuation rule became effective and that were 
``grandfathered'' under the former Sec. Sec. 206.157(c)(1)(v) and 
206.157(c)(2)(v) have been terminated. Paragraphs (c)(1)(v) and 
(c)(2)(v) were removed by the February 1996 rule discussed above. See 
61 FR at 5451. Because of the very limited explanation for that removal 
and the fact that removal of these clauses was not specifically 
mentioned in the August 1995 proposed rule, disputes have arisen 
regarding the continued validity after March 1996 of pre-1988 
allowances that had continued in effect under the ``grandfathering'' 
provisions. The MMS reaffirms its view that the pre-1988 allowances 
were terminated effective March 1, 1996, when the ``grandfathering'' 
provisions were removed. But regardless of the outcome of disputes as 
to the continued validity of ``grandfathered'' allowances between 1996 
and the present, MMS proposes to specifically clarify that lessees may 
not use such allowances prospectively.
    The proposed rule also would amend Sec.  206.157(f), which 
identifies allowable costs in determining transportation allowances, in 
three respects. One proposed change would conform the rule with recent 
judicial precedent. The other two proposed amendments are analogous to 
the recently-amended Federal crude oil valuation rule (69 FR 24959, May 
5, 2004).
    First, MMS proposes to amend 206.157(f)(1) regarding firm demand 
charges (sometimes called reservation fees). The current rule provides:

    Firm demand charges paid to pipelines. You must limit the 
allowable costs for 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;

The rule thus prohibits lessees from deducting unused firm demand 
charges.
    Section 206.157(f) was promulgated as part of a rule amendment 
published on December 16, 1997 (62 FR 65762) (effective February 1, 
1998). The 1998 rule amendment specified which of the various costs 
addressed in and itemized under FERC Order 636 either were deductible 
or nondeductible in calculating transportation allowances. The 
producing industry challenged the rule in Independent Petroleum 
Association of America et al. v. Armstrong, Nos. 1:98CV00531 and 
1:98CV00631 (D.D.C.). The primary issue in the litigation was the 
lessee's duty to market production at no cost to the lessor, which the 
rule formally codified at 30 CFR 206.152(i) and 206.153(i). But among 
the other provisions that the producing industry challenged was the 
prohibition against deducting unused firm demand charges in Sec.  
206.157(f)(1).
    In IPAA v. Armstrong, the district court initially declared the 
entire rule unlawful. 91 F. Supp. 2d 117, 130 (D.D.C. 2000). On April 
10, 2000, the Federal Government moved to alter or amend the judgment 
under Rule 59(e), Fed. R. Civ.P. Among other things, the Government 
explained:

    The Court's Order and Final Judgment states that 30 CFR 
206.157(f)(1) (Federal leases) and 206.177(f)(1) (Indian leases) are 
invalidated without further clarification. These sections of the 
challenged rule allow so-called ``firm demand'' charges--charges 
that shippers pay to pipelines to reserve pipeline capacity--to be 
deducted as transportation costs, but limit the deductibility of 
these costs to the costs incurred for the actual volumes 
transported.
    In limiting the deductibility of these costs to the actual 
volumes transported, these provisions correspondingly provide that 
lessees may not take into account in calculating the allowance ``any 
gains associated with releasing firm capacity''--i.e., selling 
unused firm capacity to other producer-shippers. In other words, 
both the cost of unused firm capacity and revenues derived from 
selling unused firm capacity are disregarded under the rule and are 
irrelevant in calculating the allowance.
    However, the rule does require lessees to reduce the firm demand 
charge claimed as a transportation allowance by the amount of any 
payment or credit received from the pipeline. Id. This ensures that, 
if a lessee in the end pays less than the cost originally paid for 
transportation and used in calculating the allowance originally 
reported, the lessee will reduce the earlier transportation cost to 
prevent the allowance of a deduction for transportation costs which 
it has not actually paid to the pipeline.\2\
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    \2\ IPAA challenges that principle at pp. 41-43 of its original 
brief, but the Court's Opinion contains no discussion of this issue. 
Defendants thus infer that the Court did not mean to invalidate this 
provision of the cited paragraphs.
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    In their briefs in this case, Plaintiffs challenged MMS' refusal 
to allow the costs of unused firm capacity as a transportation cost 
deduction. At pages 24-25 of the Court's Opinion, the Court seems to 
indicate some belief that disallowance of unused firm demand charges 
was arbitrary, but there was no further discussion of this provision 
in the Opinion. The Order and Final Judgment then stated only that 
the cited paragraphs were invalid.
    Consequently, it appears to Defendants that the Court intended 
to declare 30 CFR 206.157(f)(1) and 206.177(f)(1) unlawful only with 
regard to that portion of the regulations which disallows a 
deduction for unused capacity, and not with regard to those 
additional provisions discussed above. But invalidating the 
disallowance of unused firm demand charges (and therefore allowing 
lessees to deduct them as part of transportation costs) necessarily 
affects the other provisions of these paragraphs. Accordingly, 
Defendants seek clarification from the Court.
    Before the Court's decision here, when unused firm demand 
charges were disallowed, there correspondingly was no consequence 
for the allowance calculation if the lessee sold all or part of its 
unused firm capacity. If lessees now may deduct unused firm demand 
charges, and report transportation allowances on that basis, it 
necessarily follows that if a lessee sells unused firm capacity, it 
must reduce the reported allowance and pay the resulting royalties 
due. This necessarily follows from the gross proceeds rule. If a 
lessee initially reported a transportation allowance in an amount 
greater than its ultimate transportation costs, it must amend its 
royalty reports and pay the additional royalties.
    For these reasons, the attached proposed amended judgment both 
clarifies which portions of these paragraphs have been held invalid 
and requires lessees to amend their reports and pay additional 
royalties if they sell firm capacity the costs of which previously 
had been included in a reported allowance.

Defendants' Motion to Alter or Amend the Judgment, April 10, 2000, at 
4-6. On September 1, 2000 (2000 U.S. Dist. LEXIS 22478), the Court 
granted the motion to alter or amend, and entered an Amended Order that 
read in relevant part as follows:

    The court hereby declares that the following regulations are 
unlawful and of no force or effect:
* * * * *
    2. Those provisions of 30 CFR 206.157(f)(1) and 206.177(f)(1) to 
the extent that they limit allowable costs for firm demand charges 
in determining transportation allowances to the applicable rate per 
MMBtu multiplied by the actual volumes transported; however, to the 
extent that a lessee sells unused firm capacity, and if the cost of 
that unused firm capacity was included in a previously reported 
transportation allowance, the lessee must amend its royalty reports 
to reduce the transportation allowance by the revenue derived from 
the sale of the firm capacity, and pay any resulting royalty and 
late payment interest due.


[[Page 43949]]


Amended Order and Final Judgment, September 1, 2000, at 1-2.
    The Government appealed the district court's decision. In 
Independent Petroleum Association of America v. DeWitt, 279 F.3d 1036 
(D.C. Cir. 2002), cert. denied, --U.S. --, 123 S. Ct. 869 (2003), the 
Court of Appeals for the District of Columbia Circuit reversed the 
district court on the principal issue in the litigation, the lessee's 
duty to market production at no cost to the lessor, and upheld the rule 
generally. However, with respect to firm demand charges, the D.C. 
Circuit held:

    ``Unused'' firm demand charges. Shippers of natural gas may 
choose among different degrees of assurance that space will be 
available for their shipments, paying (naturally) for extra 
security. By paying a firm demand charge (an upfront reservation 
fee), they secure a guaranteed amount of continuously available 
pipeline capacity; when they actually ship, they incur a ``commodity 
charge'' for the transport itself. The reservation fee, however, is 
nonrefundable--the cost of any reserved capacity that a lessee 
ultimately cannot use will be lost unless it is able to resell the 
capacity. (Recall that the district court amended the summary 
judgment order, at the behest of the government, to provide for a 
credit to the government in the event of such resales.) In contrast, 
with ``interruptible'' service, shippers pay no reservation fee, but 
their access to pipeline capacity is subject to the changing needs 
of other, higher priority customers (i.e., those who pay for firm 
demand). Producers claim that the unused firm demand charges are 
part of their actual transportation costs, and thus should be 
deductible.
    In defense of its contrary view, Interior said only that it does 
``not consider the amount paid for unused capacity as a 
transportation cost,'' Final Rule, 62 FR at 65757/1, not revealing 
to what category such expenses did belong. In its opening brief, it 
quotes its prior assertion and declares that the district court must 
be reversed because it ``offered no cogent reason for rejecting this 
distinction.'' Interior Br. at 43. But Interior has offered no 
``distinction'' at all, only an unusually raw ipse dixit. On its 
face, it is hard to see how money paid for assurance of secure 
transportation is not ``for transportation''; the cost of freight 
insurance looks like a shipping expense, for example, even if the 
goods arrive without difficulty and the premium therefore goes 
``unused.'' And Interior makes no suggestion that producers have 
incurred such fees extravagantly--an extravagance that seems 
unlikely, as under the ordinary \1/8\ lease the producer would bear 
\7/8\ of the loss. Further, under the crediting arrangement provided 
by the district court order, the government will share in any 
recovery of ``unused'' charge, a recovery that producers have strong 
incentives to pursue. While some reason may lurk behind the 
government's position, it has offered none, and we have no basis for 
sustaining its conclusion. See, e.g., Motor Vehicle Manufacturers 
Ass'n., Inc. v. State Farm Mut. Auto Ins. Co., 463 U.S. 29, 43 
(1983).
    The judgment of the district court is reversed on all issues 
except for its ruling on unused firm demand charges, which we 
affirm.

279 F.3d at 1042-1043.
    The MMS therefore proposes to amend 30 CFR 206.157(f)(1) to conform 
with the D.C. Circuit's decision, so as to allow lessees to deduct 
unused firm demand charges, and to provide for reduction of previously 
reported transportation allowances in the event the lessee sells unused 
firm capacity after including it as part of that previously reported 
allowance. The proposed amended provision would read:

    (1) Firm demand charges paid to pipelines. You may deduct firm 
demand charges or capacity reservation fees paid to a pipeline, 
including charges or fees for unused firm capacity that you have not 
sold before you report your allowance. If you receive a payment from 
any party for release or sale of firm capacity after reporting a 
transportation allowance that included the cost of that unused firm 
capacity, or 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 by the 
amount of that payment. You must modify the Form MMS-2014 by the 
amount received or credited for the affected reporting period, and 
pay any resulting royalty and late payment interest due;
    (2) * * *.

    Second, MMS proposes to amend Sec.  206.157(f)(7), addressing 
actual and theoretical line losses. The current rule prohibits 
deduction of both actual and theoretical line losses under non-arm's-
length transportation arrangements unless the allowance is based on a 
FERC- or State regulatory-approved tariff. In the recently-amended 
Federal crude oil valuation rule (69 FR 24959, May 5, 2004), MMS 
allowed actual, but not theoretical, line losses under non-arm's-length 
transportation arrangements. As MMS explained in the preamble to that 
final rule, MMS believes that actual line losses properly may be 
regarded as a cost of moving production. In addition, if there is a 
line gain, the lessee must reduce its transportation allowance 
accordingly. In a non-arm's-length situation, however, a charge for 
theoretical line losses would be artificial and would not be an actual 
cost to the lessee. While a lessee may have to pay an amount to a 
pipeline operator for theoretical line losses as part of an arm's-
length tariff, in a non-arm's-length situation, line losses, like other 
costs, should be limited to actual costs incurred. (However, if a non-
arm's-length transportation allowance is based on a FERC- or State 
regulatory-approved tariff that includes a payment for theoretical line 
losses, that cost would be allowed, as the current rule already 
provides.)
    The MMS also proposes to amend Sec.  206.157(f) by adding a new 
paragraph (f)(10) to allow lessees to deduct the costs of securing a 
letter of credit or other surety that the pipeline requires a shipper 
to maintain under an arm's-length contract. The MMS recently-amended 
Federal crude oil valuation rule (69 FR 24959, May 5, 2004) allows this 
cost in arm's-length situations. The MMS believes that this is a cost 
that the lessee must incur to obtain the pipeline's transportation 
service, and therefore is a cost of moving the gas. These costs may 
include only the costs currently allocable to production from the 
Federal lease. In non-arm's-length situations, MMS expects that 
requiring a letter of credit from an affiliated producer is unnecessary 
and that the corporate organization ordinarily would avoid incurring 
the costs of the premium necessary for the letter of credit. MMS 
therefore believes it inappropriate to allow such a deduction.
    A surety may take any of several forms--for example, a letter of 
credit, a bond, or a cash deposit on which a pipeline may draw in the 
event of nonpayment of transportation charges. To illustrate the 
principle that the costs may include only the costs of surety that are 
allocable to the Federal lease or leases, assume hypothetically that 
you make a cash deposit of 2 months of the expected transportation 
charges (assume $50,000), and transport 100,000 MMBtu per month, of 
which 75,000 MMBtu are produced from a Federal lease. You would 
calculate the cost of the cash deposit in this example as follows:
    (i) Calculate the monthly rate of return representing your cost of 
capital in making the cash deposit. In this example, if the Standard 
and Poor's BBB rating is 8 percent, the allowable annual rate would be 
1.3 x .08 = .104. Divide the annual rate by 12 to obtain a monthly 
rate. The allowable monthly rate therefore would be .104/12 = .008667.
    (ii) Multiply that monthly rate of return by the amount of the 
deposit ($50,000) to get the monthly cost, which would be $50,000 x 
.008667 = $433.33.
    (iii) Then multiply that result by the proportion of total 
production that is produced from the Federal lease to calculate the 
share of that amount applicable to the Federal lease. In this example, 
the proportion of production applicable to the Federal lease is 75,000 
MMBtu/100,000 MMBtu = \3/4\. So you

[[Page 43950]]

could include in your transportation costs $433.33 x .75 = $325 as an 
allowable transportation cost for as long as the $50,000 is on deposit 
(and the other factors remain unchanged).
    The expense of a letter of credit or other surety would be treated 
similarly. If you pay a bank $5,000 as a non-refundable fee for a 
letter of credit, you could include the proportion allocable to Federal 
production in the month that fee is paid (and then never again), or you 
may calculate a monthly cost of that $5,000 (similar to calculating the 
cost of the cash deposit) and include that monthly cost as part of the 
transportation allowance reported each month for the life of the 
transportation contract. The MMS welcomes comments on whether these are 
reasonable ways to calculate the actual costs of sureties that 
pipelines require from shippers.
    The MMS seeks comments regarding whether these various costs should 
be allowed, and whether there are other costs directly attributable to 
the transportation of gas that should be included in the final rule.
    Finally, MMS proposes to amend Sec.  206.157(g) to add new 
paragraphs (g)(5), (g)(6), and (g)(7), and to redesignate the current 
paragraph (g)(5) as paragraph (g)(8), to further specify other costs 
that are not allowable in determining transportation allowances. These 
nonallowable costs include:
     Fees paid to brokers. This includes fees paid to parties 
who arrange marketing or transportation, if such fees are separately 
identified from aggregator/marketer fees. The MMS believes such fees 
are marketing costs and are not actual costs of transportation.
     Fees paid to scheduling service providers. This includes 
fees paid to parties who provide scheduling services, if such fees are 
separately identified from aggregator/marketer fees. The MMS believes 
that these costs are marketing or administrative costs that lessees 
must bear at their own expense and are not actual costs of 
transportation.
     Internal costs, including salaries and related costs, 
rent/space costs, office equipment costs, legal fees, and other costs 
to schedule, nominate, and account for sale or movement of production. 
These costs never have been deductible, and MMS proposes to expressly 
reaffirm this principle for clarity.
    The recently-amended Federal crude oil valuation rule (69 FR 24959, 
May 5, 2004) identifies these costs as non-deductible, and the proposal 
here would make the two rules consistent.
    The proposed paragraph (g)(8), addressing ``other nonallowable 
costs,'' is the current paragraph (g)(5) renumbered.
    The MMS does not believe that any of the above-described costs are 
incurred as part of the process of physically moving gas. The MMS seeks 
comments on whether any of these costs should be deductible.

III. Procedural Matters

1. Public Comment Policy

    Our practice is to make comments, including names and home 
addresses of respondents, available for public review during regular 
business hours and on our Internet site at www.mrm.mms.gov. Individual 
respondents may request that we withhold their home address from the 
rulemaking record, which we will honor to the extent allowable by law. 
There also may be circumstances in which we would withhold from the 
rulemaking record a respondent's identity, as allowable by law. If you 
wish us to withhold your name and/or address, you must state this 
prominently at the beginning of your comments. However, we will not 
consider anonymous comments. We will make all submissions from 
organizations or businesses, and from individuals identifying 
themselves as representatives or officials of organizations or 
businesses, available for public inspection in their entirety.

2. Summary Cost and Royalty Impact Data

    Summarized below are the estimated costs and benefits of the 
proposed rule to all potentially affected groups: Industry, the Federal 
Government, and State and local governments. The costs and the royalty 
collection impacts, are segregated into two categories--those that 
would accrue in the first year after the proposed rule becomes 
effective and those that would accrue on a continuing basis each year 
thereafter. Of the five proposed changes that have cost impacts, four 
will result in royalty decreases for industry, States, and MMS. One 
change will result in a royalty increase. The net impact of the five 
changes will result in an expected overall royalty decrease of 
$6,916,000, as itemized below.
A. Industry
    (1) Net decrease in royalties--Allowable transportation deduction 
for unused firm demand charges. Under this proposed rule, industry 
would be allowed to deduct the portion of firm demand charges it paid 
``arm's-length'' to a pipeline, but did not use. Currently, industry 
may deduct only the firm demand rate per MMBtu applied to the actual 
volume transported. Therefore, calculating the estimated royalty 
decrease would be accomplished by determining the total firm demand 
charges paid to a pipeline and then determining the portion of capacity 
that is unused. For example, if the lessee ships only 80 percent of the 
firm capacity it paid for, then it would be able to deduct an 
additional 20 percent of the total firm demand charges paid. For 
estimating the annual royalty decrease of this provision of the 
proposed rule, the following data and assumptions are used:
    The total transportation allowances deducted by Federal lessees 
from gas royalties for FY 2002 were approximately $103,789,000. While 
MMS does not maintain data or request information regarding the 
percentage of transportation allowances that fall under either the 
arm's-length or non-arm's-length category, we believe that gas, unlike 
oil, is typically transported through interstate pipelines not owned by 
the lessee. Therefore, we estimate that 75 percent of all gas 
transportation allowances are arm's-length. We also made the following 
two assumptions: (1) On average, firm demand charges account for less 
than 20 percent of arm's-length transportation payments made by Federal 
lessees to transport gas away from the lease to a sales point (because 
of their steep cost and level of service, firm demand charges are 
predominantly paid to pipelines by local distribution companies to 
guarantee delivery of gas to retail customers), and (2) the amount of 
unused capacity is 25 percent (although capacity utilization can vary 
widely from pipe to pipe and from time to time, minimum volumes of gas 
flowing through an interstate pipeline are typically around 75 percent 
of the total pipeline capacity). Using these parameters as a maximum 
estimate of the revenue impact, the royalty decrease for industry 
resulting from deducting unused firm demand charges would be at most 
$3,892,000 ($103,789,000 x 0.75 x 0.2 x 0.25).
    (2) Net decrease in royalties--Increase Rate of Return in non-
arm's-length situations from 1 times the Standard and Poor's BBB bond 
rate to 1.3 times the Standard and Poor's BBB bond rate. Based on the 
above estimate of arm's-length transportation usage, we assumed that 25 
percent of all reported gas transportation allowances are non-arm's-
length. We also assumed that over the life of the pipeline, allowance 
rates are made up of \1/3\ rate of return on undepreciated capital 
investment, \1/3\

[[Page 43951]]

depreciation expenses and \1/3\ operation, maintenance and overhead 
expenses (these are the same assumptions used in the recent threshold 
analysis for the Federal oil valuation rulemaking). Based on total gas 
transportation allowance deductions of $103,789,000 for FY 2002, and 
our assumptions regarding the makeup of the allowance components, the 
portion of allowances attributable to the rate of return would be 
approximately $8,649,000. Therefore, we estimated that increasing the 
basis for the rate of return by 30 percent could result in additional 
allowance deductions of $2,594,725 ($8,649,000 x .30). That is, the net 
decrease in royalties paid by industry would be approximately 
$2,595,000.
    (3a) Net decrease in royalties--Allow Line Loss as a component of a 
non-arm's-length transportation allowance. For this analysis, we 
assumed that gas pipeline losses are 0.2 percent of the volume 
transported through the pipeline, which would also equate to 0.2 
percent of the value of the Federal royalty share of gas production 
transported. For FY 2002, the total value of the Federal gas royalty 
share subject to transportation allowances was approximately 
$2,506,447,000. Assuming 25 percent of that amount was associated with 
non-arm's-length transportation, the value of the line loss would be 
$1,253,224 ($2,506,447,000 x .25 x .002). Therefore, the net decrease 
in royalties would be approximately $1,253,000 annually.
    (3b) Net decrease in royalties--Allow the cost of a Letter of 
Credit as a component of an arm's-length transportation allowance. The 
cost of a letter of credit is based on the volume of gas transported 
through a pipeline under third-party transportation. Therefore, in 
estimating the annual royalty impact of this provision, we first 
estimated the total volume of the FY 2002 Federal gas royalty share 
that would be subject to a transportation allowance. We estimated that 
volume would be no more than 80 percent of the total Federal gas 
royalty share onshore and offshore. We also estimated that, based on 
the total sales volume of gas from Federal onshore and offshore leases 
(5,821,978,000 Mcf) and the average onshore and offshore royalty rate 
of 13.55 percent, the royalty share of Federal gas production subject 
to a transportation allowance would be approximately 631,000,000 Mcf. 
Next, we assumed that 75 percent of that volume would be transported at 
arm's length, and that typical letter of credit costs would be at most 
$0.03 per Mcf for 2 months (or \1/6\ of a year) supply of gas 
transported. Finally, we assumed that only 20 percent of those shippers 
(by volume) did not meet the pipeline credit standards and were 
required to post a letter of credit, because most Federal gas is 
transported by major oil corporations with A or higher credit ratings. 
We thus estimated that the additional cost to industry for which an 
allowance deduction could be taken against royalties would be no more 
than approximately $473,000 per year (631,000,000 x .75 x .2 x \1/6\ x 
$0.03).
    (4) Net increase in royalties--Require computation under the 
exception to use non-arm's-length transportation costs to be based on 
actual arm's-length charges instead of the FERC tariff rate. Our 
database for requests to use a FERC-approved tariff as an exception to 
non-arm's-length transportation costs indicates that MMS has received 
94 such requests dating back to 1990 (When approved, these exceptions 
would continue year after year). Therefore, it is apparent that use of 
the exception is widespread under non-arm's-length transportation 
situations. Therefore, for this revenue impact analysis, we assumed 
that at least 50 percent of the non-arm's-length allowances are based 
on a FERC tariff. (We are not aware of any State-approved tariffs being 
used). Because we do not have any data suggesting what the average FERC 
tariff rate would be nationwide, due to significantly varying market 
conditions, locational differences, and myriad tariff structures, we 
must assume a conservative estimate regarding the percentage discount 
to the tariff that would be negotiated by arm's-length shippers. We 
believe, on average, a reasonable discount that would be paid under the 
FERC tariff would be 90 percent of the full tariff rate. Therefore, 
under the new proposed provision, lessees would be allowed to deduct 
only 90 percent of the tariff rate, instead of 100 percent, a 10 
percent reduction in the reported allowance amount. Using these 
assumptions (including the assumption that 25 percent of reported 
transportation allowances are non-arm's-length), we estimate that 
royalties will therefore increase by about $1,297,000 per year 
($103,789,000 x .25 x .5 x .1 = $1,297,000).
B. State and Local Governments
    This rule will not impose any additional burden on local 
governments. The MMS estimates that States impacted by this rule would 
receive an overall decrease in royalties as indicated below:
    States receiving revenues from offshore Outer Continental Shelf 
Lands Act Section 8(g) leases would share in a portion of the reduced 
royalties resulting from additional transportation allowance deductions 
claimed by industry. Based on the ratio of offshore Federal revenues 
disbursed to States for section 8(g) leases (.61 percent), it is 
assumed that the same proportion of allowance deductions for offshore 
transportation would impact those State revenues. Of the $103,789,000 
total gas transportation allowance deductions for FY 2002, $52,363,000 
(or about 50.5 percent) was attributable to offshore production. Using 
the total revenue impacts calculated under A.(1), (2), (3a), (3b), and 
(4) above ($6,916,000) applied to offshore production using the 
offshore factor of 50.5 percent, and the disbursement percentage 
attributable to section 8(g) leases from Federal offshore revenues of 
.61 percent, the net offshore impact on State revenues for 8(g) lease 
would be approximately $21,000 (($6,916,000 x .505 x 0.0061 = $21,000). 
Using the factor of .0030805 (.505 x .0061) applied to the royalty 
decrease or increase, the impact of each proposed change described 
above can be easily computed for the States:
    (1) Net decrease in royalties--Allowable transportation deduction 
for unused firm demand charges. $3,892,000 x .0030805 = $11,989.
    (2) Net decrease in royalties--Increase Rate of Return in non-
arm's-length situations from 1 times the Standard and Poor's BBB bond 
rate to 1.3 times the Standard and Poor's BBB bond rate. $2,595,000 x 
.0030805 = $7,994.
    (3a) Net decrease in royalties--Allow Line Loss as a component of a 
non-arm's-length transportation allowance. $1,253,000 x .0030805 = 
$3,860.
    (3b) Net decrease in royalties--Allow the cost of a Letter of 
Credit as a component of an arm's-length transportation allowance. 
$473,000 x .0030805 = $1,457.
    (4) Net increase in royalties--Require computation under the 
exception to use non-arm's-length transportation costs to be based on 
actual arm's-length charges instead of the FERC tariff rate. $1,297,000 
x .0030805 = $3,995.
    For States receiving 50 percent of the revenues from onshore 
Federal lands (onshore transportation allowances account for 49.5 
percent of the total gas transportation allowance deductions for FY 
2002), the estimated net onshore impact would be approximately 
$1,712,000 ($6,916,000 x .495 x .5 = $1,712,000). Using the factor of 
.2475 (.495 x .5) applied to the royalty decrease or increase, the 
impact of each proposed change described above can be easily computed 
for the States:
    (1) Net decrease in royalties--Allowable transportation deduction 
for

[[Page 43952]]

unused firm demand charges. $3,892,000 x .2475 = $963,270.
    (2) Net decrease in royalties--Increase Rate of Return in non-
arm's-length situations from 1 times the Standard and Poor's BBB bond 
rate to 1.3 times the Standard and Poor's BBB bond rate. $2,595,000 x 
.2475 = $642,263.
    (3a) Net decrease in royalties--Allow Line Loss as a component of a 
non-arm's-length transportation allowance. $1,253,000 x .2475 = 
$310,118.
    (3b) Net decrease in royalties--Allow the cost of a Letter of 
Credit as a component of an arm's-length transportation allowance. 
$473,000 x .2475 = $117,067.
    (4) Net increase in royalties--Require computation under the 
exception to use non-arm's-length transportation costs to be based on 
actual arm's-length charges instead of the FERC tariff rate. $1,297,000 
x .2475 = $321,007.
    The total impact on all States from offshore and onshore production 
would be $1,733,000, representing the net impact of the royalty 
decreases and the royalty increase from offshore and onshore. For each 
proposed change, the total impact on the States would be the sum of the 
8(g) impacts plus the onshore impacts itemized above:
    (1) Net decrease in royalties--Allowable transportation deduction 
for unused firm demand charges. $11,989 + $963,270 = $975,259.
    (2) Net decrease in royalties--Increase Rate of Return in non-
arm's-length situations from 1 times the Standard and Poor's BBB bond 
rate to 1.3 times the Standard and Poor's BBB bond rate. $7,994 + 
642,263 = $650,257.
    (3a) Net decrease in royalties--Allow Line Loss as a component of a 
non-arm's-length transportation allowance. $3,860 + $310,118 = 
$313,978.
    (3b) Net decrease in royalties--Allow the cost of a Letter of 
Credit as a component of an arm's-length transportation allowance. 
$1,457 + 117,067 = $118,5.
    (4) Net increase in royalties--Require computation under the 
exception to use non-arm's-length transportation costs to be based on 
actual arm's-length charges instead of the FERC tariff rate. $3,995 + 
$321,007 = $325,002.
C. Federal Government
    The Federal Government, like the States, would be impacted by a net 
overall decrease in royalties as a result of the proposed changes to 
the regulations governing transportation allowance computations. In 
fact, the royalty decrease experienced by the Federal Government would 
be the difference between the total royalty decrease benefiting 
industry and the royalty decrease affecting the States. In other words, 
the royalty savings by industry would be shared proportionately between 
the States and the Federal Government as computed below. The net impact 
on the Federal Government would be approximately $5,183,000.
    (1) Net decrease in royalties--Allowable transportation deduction 
for unused firm demand charges. $3,892,000 - $975,259 = $2,916,741.
    (2) Net decrease in royalties--Increase Rate of Return in non-
arm's-length situations from 1 times the Standard and Poor's BBB bond 
rate to 1.3 times the Standard and Poor's BBB bond rate. $2,595,000 - 
$650,257 = $1,944,743.
    (3a) Net decrease in royalties--Allow Line Loss as a component of a 
non-arm's-length transportation allowance. $1,253,000 - $313,978 = 
$939,022.
    (3b) Net decrease in royalties--Allow the cost of a Letter of 
Credit as a component of an arm's-length transportation allowance. 
$473,000 - $118,524 = $354,476.
    (4) Net increase in royalties--Require computation under the 
exception to use non-arm's-length transportation costs to be based on 
actual arm's-length charges instead of the FERC tariff rate. $1,297,000 
- $325,002 = $971,998.
D. Summary of Costs and Benefits to Industry, State and Local 
Governments, and the Federal Government
    In the table, a negative number means a reduction in payment or 
receipt of royalties or a reduction in costs. A positive number means 
an increase in payment or receipt of royalties or an increase in costs. 
The net expected change in royalty impact is the sum of the royalty 
increases and decreases.

                  Summary of Costs and Royalty Impacts
------------------------------------------------------------------------
                                          Costs and royalty increases or
                                                 royalty decreases
               Description               -------------------------------
                                                            Subsequent
                                            Fiscal year        years
------------------------------------------------------------------------
                               A. Industry
------------------------------------------------------------------------
(1) Royalty Decrease--Allowable              -$8,213,000     -$8,213,000
 transportation deductions..............
(2) Royalty Increase--Restricted use of        1,297,000       1,297,000
 FERC tariff charges....................
-----------------------------------------
(3) Net Expected Change in Royalty            -6,916,000      -6,916,000
 Payments from Industry.................
-----------------------------------------
                     B. State and Local Governments
------------------------------------------------------------------------
(1) Royalty Decrease--Allowable               -2,058,000      -2,058,000
 transportation deductions..............
(2) Royalty Increase--Restricted use of          325,000         325,000
 FERC tariff charges....................
-----------------------------------------
(3) Net Expected Change in Royalty            -1,733,000      -1,733,000
 Payments to States.....................
-----------------------------------------
                          C. Federal Government
------------------------------------------------------------------------
(1) Royalty Decrease--Allowable               -6,155,000      -6,155,000
 transportation deductions..............
(2) Royalty Increase--Restricted use of          972,000         972,000
 FERC tariff charges....................
(3) Net Expected Change in Royalty            -5,183,000      -5,183,000
 Payments to Federal Government.........
------------------------------------------------------------------------


[[Page 43953]]

3. Regulatory Planning and Review, Executive Order 12866

    Under the criteria in Executive Order 12866, this proposed rule is 
not an economically significant regulatory action as it does not exceed 
the $100 million threshold. The Office of Management and Budget (OMB) 
has made the determination under Executive Order 12866 to review this 
proposed rule because it raises novel legal or policy issues.
    1. This proposed rule will not have an annual effect of $100 
million or adversely affect an economic sector, productivity, jobs, the 
environment, or other units of Government. The MMS has evaluated the 
costs of this rule, and has determined that it will impose no 
additional administrative costs.
    2. This proposed rule will not create inconsistencies with other 
agencies' actions.
    3. This proposed rule will not materially affect entitlements, 
grants, user fees, loan programs, or the rights and obligations of 
their recipients.
    4. This proposed rule will raise novel legal or policy issues. See 
Explanation of Proposed Amendments in the Preamble of this proposed 
rule.

4. Regulatory Flexibility Act

    I certify that this proposed rule will not have a significant 
economic effect on a substantial number of small entities as defined 
under the Regulatory Flexibility Act (5 U.S.C. 601 et seq.). An initial 
Regulatory Flexibility Analysis is not required. Accordingly, a Small 
Entity Compliance Guide is not required. See the above Analysis titled 
``Summary of Costs and Royalty Impacts.''
    Your comments are important. The Small Business and Agricultural 
Regulatory Enforcement Ombudsman and 10 Regional Fairness Boards were 
established to receive comments from small businesses about Federal 
agency enforcement actions. The Ombudsman will annually evaluate the 
enforcement activities and rate each agency's responsiveness to small 
business. If you wish to comment on the enforcement actions in this 
rule, call 1-800-734-3247. You may comment to the Small Business 
Administration without fear of retaliation. Disciplinary action for 
retaliation by an MMS employee may include suspension or termination 
from employment with the Department of the Interior.

5. Small Business Regulatory Enforcement Act (SBREFA)

    This proposed rule is not a major rule under 5 U.S.C. 804(2), the 
Small Business Regulatory Enforcement Fairness Act. This proposed rule:
    1. Does not have an annual effect on the economy of $100 million or 
more. See the Analysis titled ``Summary of Costs and Royalty Impacts.''
    2. Will not cause a major increase in costs or prices for 
consumers, individual industries, Federal, State, or local government 
agencies, or geographic regions.
    3. Does not have significant adverse effects on competition, 
employment, investment, productivity, innovation, or the ability of 
U.S.-based enterprises to compete with foreign-based enterprises.

6. Unfunded Mandates Reform Act

    In accordance with the Unfunded Mandates Reform Act (2 U.S.C. 1501 
et seq.):
    1. This proposed rule will not significantly or uniquely affect 
small governments. Therefore, a Small Government Agency Plan is not 
required.
    2. This proposed rule will not produce a Federal mandate of $100 
million or greater in any year; i.e., it is not a significant 
regulatory action under the Unfunded Mandates Reform Act. The analysis 
prepared for Executive Order 12866 will meet the requirements of the 
Unfunded Mandates Reform Act. See the above Analysis titled ``Summary 
of Costs and Royalty Impacts.''

7. Governmental Actions and Interference With Constitutionally 
Protected Property Rights (Takings), Executive Order 12630

    In accordance with Executive Order 12630, this proposed rule does 
not have significant takings implications. A takings implication 
assessment is not required.

8. Federalism, Executive Order 13132

    In accordance with Executive Order 13132, this proposed rule does 
not have federalism implications. A federalism assessment is not 
required. It will not substantially and directly affect the 
relationship between the Federal and State governments. The management 
of Federal leases is the responsibility of the Secretary of the 
Interior. Royalties collected from Federal leases are shared with State 
governments on a percentage basis as prescribed by law. This proposed 
rule would not alter any lease management or royalty sharing 
provisions. It would determine the value of production for royalty 
computation purposes only. This proposed rule would not impose costs on 
States or localities.

9. Civil Justice Reform, Executive Order 12988

    In accordance with Executive Order 12988, the Office of the 
Solicitor has determined that this proposed rule will not unduly burden 
the judicial system and does not meet the requirements of sections 3(a) 
and 3(b)(2) of the Order.

10. Paperwork Reduction Act of 1995

    This proposed rulemaking does not contain new information 
collections requirements nor significantly change existing information 
collection requirements; therefore, a submission to OMB is not 
required. The information collection requirements referenced in this 
proposed rule are currently approved by OMB under OMB control number 
1010-0140 (OMB approval expires October 31, 2006). The total hour 
burden currently approved under 1010-0140 is 125,856 hours. We request 
comments on whether there is an increased burden on the industry 
compared to the current rule from proposed Sec. 206.157 (b)(5) that 
would require lessees to calculate a transportation allowance based on 
the volume-weighted average of the rates paid by the third parties 
under arm's-length transportation contracts.

11. National Environmental Policy Act

    This proposed rule deals with financial matters and has no direct 
effect on MMS decisions on environmental activities. Pursuant to 516 DM 
2.3A (2), section 1.10 of 516 DM 2, Appendix 1 excludes from 
documentation in an environmental assessment or impact statement 
``policies, directives, regulations and guidelines of an 
administrative, financial, legal, technical or procedural nature; or 
the environmental effects of which are too broad, speculative or 
conjectural to lend themselves to meaningful analysis and will be 
subject later to the NEPA process, either collectively or case-by-
case.'' Section 1.3 of the same appendix clarifies that royalties and 
audits are considered to be routine financial transactions that are 
subject to categorical exclusion from the NEPA process.

12. Government-to-Government Relationship With Tribes

    In accordance with the President's memorandum of April 29, 1994, 
``Government-to-Government Relations with Native American Tribal 
Governments'' (59 FR at 22951) and 512 DM 2, we have evaluated 
potential effects on federally recognized Indian tribes and have 
determined that the changes we are proposing for Federal

[[Page 43954]]

leases will not have an impact on Indian leases.

13. Effects on the Nation's Energy Supply, Executive Order 13211

    In accordance with Executive Order 13211, this regulation does not 
have a significant adverse effect on the nation's energy supply, 
distribution, or use. The proposed changes better reflect the way 
industry accounts internally for its gas valuation and provides a 
number of technical clarifications. None of these changes should impact 
significantly the way industry does business, and accordingly should 
not affect their approach to energy development or marketing. Nor does 
the proposed rule otherwise impact energy supply, distribution, or use.

14. Consultation and Coordination With Indian Tribal Governments, 
Executive Order 13175

    In accordance with Executive Order 13175, this proposed rule does 
not have tribal implications that impose substantial direct compliance 
costs on Indian tribal governments.

15. Clarity of This Regulation

    Executive Order 12866 requires each agency to write regulations 
that are easy to understand. We invite your comments on how to make 
this rule easier to understand, including answers to questions such as 
the following: (1) Are the requirements in the rule clearly stated? (2) 
Does the rule contain technical language or jargon that interferes with 
its clarity? (3) Does the format of the rule (grouping and order of 
sections, use of headings, paragraphing, etc.) aid or reduce its 
clarity? (4) Would the rule be easier to understand if it were divided 
into more (but shorter) sections? (A ``section'' appears in bold type 
and is preceded by the symbol Sec.  and a numbered heading; for 
example, Sec.  204.200 What is the purpose of this part?) (5) Is the 
description of the rule in the Supplementary Information section of the 
preamble helpful in understanding the proposed rule? What else could we 
do to make the rule easier to understand? Send a copy of any comments 
that concern how we could make this rule easier to understand to: 
Office of Regulatory Affairs, Department of the Interior, Room 7229, 
1849 C Street, NW., Washington, DC 20240. You may also e-mail the 
comments to this address: [email protected].

List of Subjects in 30 CFR Part 206

    Continental shelf, Government contracts, Mineral royalties, Natural 
gas, Petroleum, Public lands--mineral resources.

    Dated: April 28, 2004.
Patricia Morrison,
Acting Assistant Secretary for Land and Minerals Management.

    For the reasons set forth in the preamble, part 206 of title 30 of 
the Code of Federal Regulations is proposed to be amended as follows:

PART 206--PRODUCT VALUATION

    1. The authority for part 206 continues to read as follows:

    Authority: 5 U.S.C. 301 et seq.; 25 U.S.C. 396, 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.

    2. In Sec.  206.150, paragraph (b) is revised as follows:


Sec.  206.150  Purpose and scope.

* * * * *
    (b) If the regulations in this subpart are inconsistent with:
    (1) A Federal statute;
    (2) A settlement agreement between the United States and a lessee 
resulting from administrative or judicial litigation;
    (3) A written agreement between the lessee and the MMS Director 
establishing a method to determine the value of production from any 
lease that MMS expects at least would approximate the value established 
under this subpart; or
    (4) An express provision of an oil and gas lease subject to this 
subpart, then the statute, settlement agreement, written agreement, or 
lease provision will govern to the extent of the inconsistency.
* * * * *
    3. In Sec.  206.151, a new definition of ``affiliate'' is added in 
alphabetical order and the definitions of ``allowance'' and ``arm's-
length contract'' are revised to read as follows:


Sec.  206.151  Definitions.

* * * * *
    Affiliate means a person who controls, is controlled by, or is 
under common control with another person. For purposes of this subpart:
    (1) Ownership or common ownership of more than 50 percent of the 
voting securities, or instruments of ownership, or other forms of 
ownership, of another person constitutes control. Ownership of less 
than 10 percent constitutes a presumption of noncontrol that MMS may 
rebut.
    (2) If there is ownership or common ownership of between 10 and 50 
percent of the voting securities or instruments of ownership, or other 
forms of ownership, of another person, MMS will consider the following 
factors in determining whether there is control under the circumstances 
of a particular case:
    (i) The extent to which there are common officers or directors;
    (ii) With respect to the voting securities, or instruments of 
ownership, or other forms of ownership: the percentage of ownership or 
common ownership, the relative percentage of ownership or common 
ownership compared to the percentage(s) of ownership by other persons, 
whether a person is the greatest single owner, or whether there is an 
opposing voting bloc of greater ownership;
    (iii) Operation of a lease, plant, pipeline, or other facility;
    (iv) The extent of participation by other owners in operations and 
day-to-day management of a lease, plant, pipeline, or other facility; 
and
    (v) Other evidence of power to exercise control over or common 
control with another person.
    (3) Regardless of any percentage of ownership or common ownership, 
relatives, either by blood or marriage, are affiliates.
    Allowance means a deduction in determining value for royalty 
purposes. Processing allowance means an allowance for the reasonable, 
actual costs of processing gas determined under this subpart. 
Transportation allowance means an allowance for the reasonable, actual 
costs of moving unprocessed gas, residue gas, or gas plant products to 
a point of sale or delivery off the lease, unit area, or communitized 
area, or away from a processing plant. The transportation allowance 
does not include gathering costs.
* * * * *
    Arm's-length contract means a contract or agreement between 
independent persons who are not affiliates and who have opposing 
economic interests regarding that contract. To be considered arm's 
length for any production month, a contract must satisfy this 
definition for that month, as well as when the contract was executed.
* * * * *
    4. Section 206.157 is amended as follows:
    A. Paragraph (b)(2)(v) is revised;
    B. Paragraph (b)(5) is revised;
    C. Paragraph (c) is revised;
    D. Paragraphs (f) introductory text, (f)(1), and (f)(7) are revised 
and paragraph (f)(10) is added; and
    E. The word ``and'' at the end of paragraph (g)(4) is removed, 
paragraph

[[Page 43955]]

(g)(5) is revised, and new paragraphs (g)(6) through (g)(8) are added.
    The additions and revisions read as follows:


Sec.  206.157  Determination of transportation allowances.

* * * * *
    (b) * * *
    (2) * * *
    (v) The rate of return must be 1.3 times the industrial rate 
associated with Standard and Poor's BBB rating. The BBB rate must be 
the monthly average rate as published in Standard and Poor's Bond Guide 
for the first month for which the allowance is applicable. The rate 
must be redetermined at the beginning of each subsequent calendar year.
* * * * *
    (5) You may apply for an exception from the requirement to compute 
actual costs under paragraphs (b)(1) through (b)(4) of this section.
    (i) The MMS will grant the exception if:
    (A) The transportation system has a tariff approved by the Federal 
Energy Regulatory Commission (FERC) or a State regulatory agency that 
FERC or the State regulatory agency has either adjudicated or 
specifically analyzed, and
    (B) Third parties are paying prices under the tariff to transport 
gas on the system under arm's-length transportation contracts.
    (ii) If MMS approves the exception, you must calculate your 
transportation allowance for each production month based on the volume-
weighted average of the rates paid by the third parties under arm's-
length transportation contracts during that production month. If during 
any production month there are no prices paid under the tariff by third 
parties to transport gas on the system under arm's-length 
transportation contracts, you may use the volume-weighted average of 
the rates paid by third parties under arm's-length transportation 
contracts in the most recent preceding production month in which third 
parties paid such rates, for up to two successive production months.
    (iii) You may use the exception under this paragraph if the tariff 
remains in effect and no more than two production months have elapsed 
since third parties paid prices under the tariff to transport gas on 
the system under arm's-length transportation contracts.
    (c) Reporting requirements--(1) Arm's-length contracts. (i) You 
must use a separate entry on Form MMS-2014 to notify MMS of a 
transportation allowance.
    (ii) The MMS may require you to submit arm's-length transportation 
contracts, production agreements, operating agreements, and related 
documents. Recordkeeping requirements are found at part 207 of this 
chapter.
    (iii) You may not use a transportation allowance that was in effect 
before March 1, 1988. You must use the provisions of this subpart to 
determine your transportation allowance.
    (2) Non-arm's-length or no contract. (i) You must use a separate 
entry on Form MMS-2014 to notify MMS of a transportation allowance.
    (ii) For new transportation facilities or arrangements, base your 
initial deduction on estimates of allowable gas transportation costs 
for the applicable period. Use the most recently available operations 
data for the transportation system or, if such data are not available, 
use estimates based on data for similar transportation systems. 
Paragraph (e) of this section will apply when you amend your report 
based on your actual costs.
    (iii) The MMS may require you to submit all data used to calculate 
the allowance deduction. Recordkeeping requirements are found at part 
207 of this chapter.
    (iv) If you are authorized under paragraph (b)(5) of this section 
to use an exception to the requirement to calculate your actual 
transportation costs, you must follow the reporting requirements of 
paragraph (c)(1) of this section.
    (v) You may not use a transportation allowance that was in effect 
before March 1, 1988. You must use the provisions of this subpart to 
determine your transportation allowance.
* * * * *
    (f) Allowable costs in determining transportation allowances. You 
may include, but are not limited to (subject to the requirements of 
paragraph (g) of this section), 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. You may not use any cost as a deduction 
that duplicates all or part of any other cost that you use under this 
paragraph.
    (1) Firm demand charges paid to pipelines. You may deduct firm 
demand charges or capacity reservation fees paid to a pipeline, 
including charges or fees for unused firm capacity that you have not 
sold before you report your allowance. If you receive a payment from 
any party for release or sale of firm capacity after reporting a 
transportation allowance that included the cost of that unused firm 
capacity, or 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 by the amount of 
that payment. You must modify the Form MMS-2014 by the amount received 
or credited for the affected reporting period, and pay any resulting 
royalty and late payment interest due;
* * * * *
    (7) Payments (either volumetric or in value) for actual or 
theoretical losses. However, theoretical losses are not deductible in 
non-arm's-length transportation arrangements unless the transportation 
allowance is based on arm's-length transportation rates charged under a 
FERC-or State regulatory-approved tariff under paragraph (b)(5) of this 
section. If you receive volumes or credit for line gain, you must 
reduce your transportation allowance accordingly and pay any resulting 
royalties and late payment interest due.
* * * * *
    (10) Costs of surety. You may deduct the costs of securing a letter 
of credit, or other surety, that the pipeline requires you as a shipper 
to maintain under an arm's-length transportation contract.
    (g) * * *
    (5) Fees paid to brokers. This includes fees paid to parties who 
arrange marketing or transportation, if such fees are separately 
identified from aggregator/marketer fees;
    (6) Fees paid to scheduling service providers. This includes fees 
paid to parties who provide scheduling services, if such fees are 
separately identified from aggregator/marketer fees;
    (7) Internal costs. This includes salaries and related costs, rent/
space costs, office equipment costs, legal fees, and other costs to 
schedule, nominate, and account for sale or movement of production; and
    (8) Other nonallowable costs. Any cost you incur for services you 
are required to provide at no cost to the lessor.
* * * * *
[FR Doc. 04-16725 Filed 7-22-04; 8:45 am]
BILLING CODE 4310-MR-P