[Federal Register Volume 70, Number 46 (Thursday, March 10, 2005)]
[Rules and Regulations]
[Pages 11869-11879]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 05-4515]


=======================================================================
-----------------------------------------------------------------------

DEPARTMENT OF THE INTERIOR

Minerals Management Service

30 CFR Part 206

RIN 1010-AD05


Federal Gas Valuation

AGENCY: Minerals Management Service (MMS), Interior.

ACTION: Final rule.

-----------------------------------------------------------------------

SUMMARY: The MMS is amending the existing regulations governing the 
valuation of gas produced from Federal leases for royalty purposes, and 
related provisions governing the reporting thereof. The current 
regulations became effective on March 1, 1988, and were amended in 1996 
and 1998. These amendments primarily affect the calculation of 
transportation deductions and the changes necessitated by judicial 
decisions since the regulations were last amended.

DATES: Effective date: June 1, 2005.

FOR FURTHER INFORMATION CONTACT: Sharron L. Gebhardt, Lead Regulatory 
Specialist, Chief of Staff Office, 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, Larry E. Cobb, Susan Lupinski, Mary A. Williams, and 
Kenneth R. Vogel of Minerals Revenue Management, MMS, Department of the 
Interior.

SUPPLEMENTARY INFORMATION:

I. Background

    The MMS is amending the existing regulations at 30 CFR 206.150 et 
seq., governing the valuation of gas produced from Federal leases for 
royalty purposes, and related provisions governing the reporting 
thereof. The current regulations became effective on March 1, 1988 (53 
FR 1230) (1988 Gas Rule).
    After conducting several public workshops, MMS issued a proposed 
rule that was published in the Federal Register on July 23, 2004 (69 FR 
43944). The comment period for the proposed rule closed on September 
21, 2004.
    The amendments do not alter the basic structure or underlying 
principles of the 1988 Gas Rule.

II. Comments on the Proposed Rule

    Comments received favored most of the proposed changes. The MMS 
received some unfavorable comments regarding future valuation 
agreements between the MMS Director and the lessee, some of the 
specifications of allowable transportation costs, and our proposal to 
change the rate of return on undepreciated capital investment in 
calculating non-arm's-length transportation allowances. Generally, we 
grouped the comments received and the MMS responses according to the 
order of the issues and proposed revisions on which we requested 
comments. We also addressed miscellaneous technical changes.

A. Spot Market Prices

    In the proposed rule, we requested comments on (1) ``whether 
publicly available spot market prices for natural gas are reliable and 
representative of market value'' and whether MMS should value natural 
gas production that is not sold at arm's-length using spot market 
prices and, if so, (2) ``how these spot market prices should be 
adjusted for location differences between the index pricing point and 
the lease.''
    Summary of Comments: One producer supported using index pricing, 
stating that index pricing provides the most accurate and transparent 
gas pricing information available and, therefore, increases royalty 
valuation certainty.
    Industry trade associations supported the use of index pricing for 
gas valuation and questioned why index pricing does not apply to arm's-
length gas sales.
    One state and the State and Tribal Royalty Audit Committee (STRAC) 
did not support using index pricing to value gas. The state claimed 
that publicly available spot prices are not a true representation of 
arm's-length market value because non-arm's-length sales are included 
within the index. The state proposed that MMS publish a new gas rule 
requiring a Federal lessee to value natural gas and associated products 
based on the first arm's-length sale of the gas or products.
    MMS Response: The written comments received continue to reflect 
disparate and conflicting views of industry and states. At the present 
time, MMS has decided not to change existing regulations for valuing 
production that is not sold at arm's-length and will continue to 
evaluate the issues.

B. Section 206.150--Purpose and Scope

    The MMS proposed to amend the Federal gas valuation rule to match 
the June 2000 Federal oil valuation rule, which provides that, if a 
written agreement between a 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. The MMS used this 
provision in the June 2000 Federal oil valuation rule to address 
unexpectedly difficult royalty valuation problems.
    Summary of Comments: Industry producers and industry trade 
associations support this change.
    Two states and STRAC do not support the use of written valuation 
agreements. One state commented that it is not in the public's best 
interest to allow the MMS Director to avoid the regulations that are 
subject to notice and comment. The states claimed that, at the very 
minimum, state approval should be necessary if this provision is 
implemented. STRAC commented that the provision is not clear and that 
state approval should be required if state royalties are affected.
    MMS Response: The MMS is mindful of the states' concerns, but does 
not believe that written valuation agreements should be subject to 
state approval (or veto). Such agreements are not an avenue to avoid 
the rules, but rather a tool to provide certainty and reduce 
administrative costs in appropriate circumstances. The rule requires 
that value under such an agreement at least approximate the value that 
would be derived under the regulations. Therefore, these agreements 
should not result in significant revenue consequences to the Federal 
Government or to the states.

C. Section 206.151--Definitions

    The MMS proposed adding a definition of ``affiliate'' and revising 
the definition of ``arm's-length contract'' to

[[Page 11870]]

be identical to the June 2000 Federal oil valuation rule, as amended, 
and to conform the Federal gas valuation rule with the DC Circuit 
holding of National Mining Association v. Department of the Interior, 
177 F.3d 1 (DC Cir. 1999). The MMS proposed revising the definition of 
``affiliate'' separately from the definition of ``arm's-length 
contract'' as in the June 2000 Federal oil valuation rule, as amended, 
to clarify and simplify the definitions.
    The MMS also proposed to revise the definition of ``transportation 
allowance'' to be consistent with the June 2000 Federal oil valuation 
rule with necessary changes in wording to apply it in the gas context. 
Finally, MMS proposed to revise the definition of ``processing 
allowance'' to make it consistent with other allowance definitions.
    Summary of Comments: Industry producers and industry trade 
associations supported the addition of ``affiliate'' but requested 
further clarification of the term ``opposing economic interests'' used 
in the definition of ``affiliate.'' One trade association urged MMS to 
adopt a presumption of opposing economic interests where common 
ownership is less than the 50 percent threshold in the definition of 
``affiliate'' for transportation and processing affiliates. One state 
also supported the proposed change to ``affiliate.''
    One state supported the definition of ``transportation allowance,'' 
but not ``to the extent it could be applied inconsistent [sic] with the 
marketability rule, such as providing for an allowance for the movement 
of unprocessed gas to a point of delivery off-lease, if that point of 
delivery is a gas plant or gas treating facility.'' One industry trade 
association recommended that the adoption of the revision be 
prospective only.
    No comments were received on the definition of ``processing 
allowance.''
    One state and STRAC suggested that the ``marketing affiliate'' 
definition should be removed from the regulations. Another state 
requested that the word ``only'' be replaced with ``any of'' in the 
definition of ``marketing affiliate'' to require valuation based on 
downstream re-sales. One industry producer requested that MMS revise 
the definition of ``gathering,'' stating that disallowing gathering 
costs is overly restrictive. One industry trade association requested a 
better definition of ``line loss.''
    MMS Response: In addition to the fact that the proposed gas rule 
did not include a discussion of the meaning of ``opposing economic 
interests,'' the question of whether two parties have opposing economic 
interests depends on the facts of a particular situation. The MMS does 
not believe that opposing economic interests should be presumed simply 
because there may be less than 50 percent common ownership between two 
entities.
    The MMS has modified the wording of the second paragraph of the 
proposed definition of ``affiliate'' to change the phrase ``between 10 
and 50 percent'' ownership or common ownership to ``10 through 50 
percent'' to be consistent with the June 2000 Federal oil valuation 
rule, as amended.
    Contrary to the comment by one state commenter, the definition of 
``transportation allowance'' is not inconsistent with the marketable 
condition rule. The commenter's view that there should be no 
transportation allowance for the movement of unprocessed gas to an off-
lease delivery point if that point is a gas plant is contrary to 30 CFR 
206.156(a), which allows a deduction for the reasonable actual costs 
incurred by the lessee to transport gas * * * from a lease to a point 
off the lease, including, if appropriate, transportation from the lease 
to a gas processing plant off the lease * * *.'' The state's comment 
reflects a view that the relationship between transportation allowances 
and the marketable condition rule should be fundamentally changed. That 
suggestion is beyond the scope of the proposal. The proposed change to 
the definition of ``transportation allowance,'' as explained in the 
preamble to the proposed rule (69 FR 43946), was to make its wording 
consistent with the June 2000 Federal crude oil valuation rule and 
return it to being substantively the same as the original 1988 rule's 
definition, with the objective of correcting an inadvertent error that 
the 1996 amendment put into the wording. That change is adopted in the 
final rule.
    The change to the wording of the definition of ``transportation 
allowance'' is prospective. However, it reflects how the rule has been 
applied in practice since the 1988 Gas Rule, even after the 1996 
amendment to that rule.
    The suggestion to eliminate the definition of ``marketing 
affiliate,'' and the suggestion to change the wording of that 
definition, are beyond the scope of the proposed gas rule. The 
suggestion of the industry commenter that gathering costs be deductible 
and the recommendation to provide a more detailed definition of line 
loss also are beyond the scope of the proposed gas rule.

D. Section 206.157 Determination of Transportation Allowances Rate of 
Return Used in Non-Arm's-Length Cost Calculations

    The MMS proposed an amendment to Sec.  206.157(b)(2)(v) governing 
calculation of actual transportation costs in non-arm's-length 
situations by changing the allowed rate of return on (1) undepreciated 
capital investment or (2) initial investment from 1.0 times the 
Standard & Poor's BBB bond rate to 1.3 times the Standard & Poor's BBB 
bond rate.
    Summary of Comments: Industry producers and one industry trade 
association supported the change but asserted that 1.3 times the 
Standard & Poor's BBB bond rate understates the cost of capital for gas 
pipelines. Based on a study from the American Petroleum Institute 
(API), industry argued that, although pipelines are not as risky as 
drilling wells, some risk is involved, and that the allowable rate of 
return should be between 1.6 and 1.8 times the Standard & Poor's BBB 
bond rate.
    The states and STRAC opposed the change. One state argued that the 
rate of return is a profit element and requested that MMS apply the 
rate of return only to non-arm's-length transportation arrangements for 
Federal offshore production if the change is implemented. STRAC also 
suggested that the proposed rate of return apply only to offshore 
production.
    Another state and STRAC asserted that interest rates have hit all 
time lows and there is no reason to implement the proposed change. As 
part of STRAC's comments, an Indian tribe suggested that increasing the 
rate of return on Federal leases may give companies an argument to 
increase the rate of return on Indian leases.
    The congressional commenter opposed the proposed change, stating 
that it would allow the weighted average cost of capital as the rate of 
return for the calculation of gas transportation allowances as 
requested by the oil and gas industry.
    MMS Response: The MMS has examined rates of return in the oil and 
gas industry and believes that some weighted average rate of return 
considering both equity and debt is appropriate as an actual market-
based cost of capital. An investor will choose to have a mix of debt 
and equity for many reasons, not the least of which is that companies 
that choose to finance their investments solely by debt will pay a 
higher interest rate due to the increased risk on the part of the 
creditor. Both debt and equity costs are

[[Page 11871]]

actual costs of capital. The choice of Standard & Poor's BBB bond rate 
in 1988 was made, at least in part, in recognition of some equity 
component because the majority of companies with non-arm's-length 
transportation arrangements have debt costs lower than the Standard & 
Poor's BBB bond rate.
    The MMS continues to believe that establishing a uniform rate of 
return on which all parties can rely is preferable to the costs, 
delays, and uncertainty inherent in attempting to analyze appropriate 
project-specific or company-specific rates of return on investment. The 
MMS, through its Economics Division, Offshore Minerals Management, has 
studied several years' worth of data for both non-integrated oil and 
gas transportation companies and larger oil and gas producers, both 
integrated and independent, that MMS believes are more likely to invest 
in gas pipelines.
    After a thorough review of the MMS and API studies, and 
consideration of the comments submitted by states and industry, we 
believe that the allowance for the rate of return on capital should be 
1.3 times the Standard & Poor's BBB bond rate. This rate is the mid-
point of the range suggested by the MMS study, which concluded that the 
range of rates of return appropriate for gas pipelines would be in the 
range of 1.1 to 1.5 times the Standard & Poor's BBB bond rate. The MMS 
also believes that, although there are some very high risks involved 
with certain oil and gas ventures, such as wildcat drilling, the risk 
associated with building and developing a pipeline to move gas that has 
already been discovered is much less and of a different nature. Both 
the MMS study and the data from the Energy Information Administration 
(EIA) demonstrate that the market also perceives that the risk is lower 
in the transportation lines of business than in the exploration and 
production lines of business.
    The MMS believes that the study conducted by its Economics 
Division, Offshore Minerals Management, used the most relevant data for 
a reasonable period and, therefore, is the best source to decide on the 
appropriate rate of return.
    The MMS does not believe that there is any basis to apply the 1.3 
times the Standard & Poor's BBB bond rate of return only to offshore 
leases. We have no evidence that rates of return for onshore pipelines 
are significantly different than for offshore pipelines.
    The fact that interest rates are currently relatively low is 
irrelevant. As interest rates rise or fall, the Standard & Poor's BBB 
bond rate will rise or fall.
    The royalty valuation for gas produced from Indian leases is now 
based on different rules than valuation of gas produced from Federal 
leases. Gas produced from Indian leases is valued primarily on the 
basis of index prices, and the rate of return is irrelevant because 
producers are allowed a 10 percent fixed deduction (with limitations). 
For gas produced from non-index zones, or from leases for which the 
tribe has elected not to use index-based valuation, there is a 
potential effect from changing the rate of return on Federal leases. If 
MMS proposes changes to the Indian gas valuation rule in the future, it 
would be appropriate to address the issue in that context.
    Finally, MMS has retained the proposed wording of paragraph 
(b)(2)(v), which is the same as the wording in the current rule except 
to change the rate of return. The wording of paragraph (b)(2)(v) is not 
identical to the wording of the equivalent provision in the Federal oil 
valuation rule, as amended, at 30 CFR 206.111(i)(2). The MMS intends 
that the two provisions have the same effect, namely, that the rate of 
return must be re-determined at the beginning of each calendar year.

E. Comments Requested on Changing the Rate of Return for Non-Arm's-
Length Processing Cost Calculations

    The MMS requested comments on changing the rate of return in Sec.  
206.159 (b)(2)(v) for non-arm's-length processing cost calculations to 
gather more information. The MMS Economics Division, Offshore Minerals 
Management, study of gas pipeline costs of capital did not study the 
impact of changing the rate of return for non-arm's-length processing 
cost calculations.
    Summary of Comments: Industry trade associations urged MMS to 
implement the same rate of return for processing cost calculations 
based on the fact that the cost of capital to an oil and gas company is 
the same, irrespective of its use. They stated that 1.3 times Standard 
& Poor's BBB bond rate is conservative and understates the cost of 
capital.
    One state and STRAC recommended that MMS not change the rate of 
return for non-arm's-length processing cost calculations. STRAC stated 
that, if the increase is implemented, MMS should retain the Standard & 
Poor's BBB bond rate, with no multiplier, for gas produced from onshore 
leases.
    MMS Response: In the preamble of the proposed rule, MMS stated that 
it ``welcomes comments, data, and analysis'' on the issue of whether 
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 (69 FR 43947). The MMS explained that, if it ``obtains 
sufficient information and data through the comment process to support 
a change,'' it may change the rate of return for non-arm's-length 
processing cost calculations. Id. While industry suggested applying the 
1.3 times the Standard & Poor's BBB bond rate to calculation of non-
arm's-length processing allowances, no commenter submitted any 
information or data that would support changing the current processing 
allowance rate. Industry did suggest that an industry-wide rate of 
return should be used. As MMS explained in the discussion of 
transportation rates of return, MMS believes that it is appropriate to 
use different rates of return for different industry lines of business. 
It is clear that the risk in exploration and development is greater 
than the risks in transportation or processing. The MMS was able to 
study rates of return in the transportation segment, but the study did 
not extend to processing rates of return. Therefore, we are not 
adopting any changes to the rate of return used in calculating 
processing allowances.

F. Section 206.157(b)(5)--Determination of Transportation Allowances--
Alternatives to Actual Cost Calculation

    The proposed provision would allow 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 that FERC or the state agency has either adjudicated or 
specifically analyzed, and third parties are paying prices under the 
tariff to transport gas under arm's-length transportation contracts.
    Summary of Comments: One state, two industry trade associations, 
and STRAC supported the proposed changes. One industry trade 
association suggested extending the 2-month production period to 3 or 6 
months to avoid frequent switching back and forth between calculating 
actual costs and using third-party tariff rates. The state commented 
that, if the exception based on the weighted average of rates paid by 
third parties is used, it be limited to the rates used for ``like 
quantities'' (presumably meaning quantities similar to those 
transported under the non-arm's-length arrangement).
    One industry association commented that the addition of the need 
for the tariff to be adjudicated or specifically

[[Page 11872]]

analyzed should be clarified or eliminated because it was unclear as to 
how this requirement would be applied. The association also commented 
that producers should be allowed to use the exception once it was 
applied for, without the need for MMS approval.
    Two states, one industry trade association, and the congressional 
commenter opposed the proposed changes. One state commented that MMS 
does not have the same FERC or state business perspective, and MMS 
should not move away from basing non-arm's-length transportation 
charges on actual costs. Another state commented that the use of 
tariffs for non-arm's-length transportation allowances should be 
deleted. The industry trade association commented that the current 
FERC-or state-approved tariffs are fair and reasonable transportation 
charges and provide certainty to industry and the MMS. The industry 
trade association also asserted that the proposal is in direct 
opposition to FERC Order 2004-A.
    MMS Response: As MMS explained in 1988, when it first adopted an 
exception from the requirement to use actual costs in non-arm's-length 
transportation arrangements, MMS believed that it was reasonable to 
rely on another regulatory agency with jurisdiction over the prices 
charged. Since that time, MMS has noted several problems with simply 
deferring to FERC or state regulatory agencies. First, MMS realized 
that the requirements for granting an exception under the current rule 
were burdensome and difficult to apply. Second, MMS now understands 
that many pipelines grant discounts to their tariffs, and there is no 
reason for a non-arm's-length shipper to be able to deduct more than 
the arm's-length shippers can deduct, nor more than its actual payment 
or transfer price to its affiliated pipeline. Lessees have always been 
limited to ``actual,'' as well as ``reasonable'' costs.
    The MMS agrees that it may be difficult for lessees to know when or 
if a transportation tariff has been ``approved'' or ``adjudicated or 
specifically analyzed.'' Therefore, MMS has changed the language of the 
exception in the final rule to more closely follow the FERC procedures. 
The regulation now requires that the tariff be filed and that the FERC 
or state regulatory agency has permitted the tariff to become 
effective.
    The MMS does agree that limiting the ability to use the exception 
for 2 months following the last arm's-length transaction may be unduly 
restrictive. While transportation arrangements normally are stable, MMS 
believes that it is possible for shippers to stop shipping for as long 
as a heating season. Heating season sales contracts typically last for 
5 months. Therefore, MMS is adjusting the ability of a non-arm's-length 
shipper to use the exception for 5 months following the last arm's-
length transaction. The MMS has also changed the wording of 
subparagraphs (b)(5)(ii) and (iii) to specify which rate to use in 
determining a transportation allowance under the exception and to 
eliminate duplicative language in the proposed rule.
    The MMS does not believe it is appropriate for lessees to use this 
exception without MMS approval. The MMS believes that it needs to know 
when companies intend to use this exception so that it can monitor 
which method a company is using, and verify that the tariff has become 
effective. Under this exception, MMS may retroactively approve an 
allowance as far back as the date the tariff is filed, so there is no 
loss to the lessee. Because MMS now pays interest on overpayments, the 
lessee will not experience a loss of the time value of money.
    The MMS does not believe it is practical to try to find arm's-
length transportation contracts of ``like quantity.'' Even though it is 
likely that the non-arm's-length shippers may ship much larger 
quantities than the arm's-length shippers, MMS believes that it is 
reasonable to use the weighted average of all arm's-length contracts. 
The MMS does not believe that FERC Order 2004-A interferes with the 
ability of a producer to comply with the requirement to know the prices 
charged to arm's-length shippers. The Order specifically requires the 
pipeline to publish all relevant information about each discount given, 
including rate, execution date, length of contract, quantity scheduled, 
etc. If a lessee cannot determine the actual volumes shipped under 
these arm's-length contracts, the lessee may use the published maximum 
daily quantities as a proxy for actual volumes. Also, the lessee may 
propose to MMS an alternate method of calculating the weighted average 
price received by the pipeline affiliate for arm's-length shipments 
under a tariff for a pipeline segment.
    On the other hand, FERC Order 2004-A does seem to make it more 
difficult for a lessee to know its affiliated pipeline's actual costs 
unless the pipeline shares that information with the public. The MMS's 
requirement to use actual costs pre-dates the new FERC information-
sharing restrictions and no one either protested the Order on this 
ground or informed MMS that the Order would interfere with compliance 
with the Federal gas valuation rule. The MMS does not plan to change 
the requirement to use actual costs and will work with any lessee that 
is unable to compute actual costs under the existing regulation. To 
make clear the ability of a regulated pipeline to share the data 
necessary for an affiliated lessee to accurately report its 
transportation deduction, whether it is based on actual costs or on the 
weighted average of arm's-length transactions, MMS intends to petition 
the FERC for a declaratory order, which would specify the parameters of 
the authority of regulated pipelines to share information with MMS and 
with their affiliated lessee.

G. Section 206.157(c)--Transportation Allowances--Reporting 
Requirements

    The MMS proposed eliminating the requirement to report separate 
line entries for allowances on the Form MMS-2014 because MMS modified 
the form in 2001. The MMS also proposed rewording new paragraph (c) to 
be consistent with the June 2000 Federal oil valuation rule regarding 
reporting requirements for arm's-length and non-arm's-length 
transportation contracts, respectively. The MMS further proposed adding 
new paragraphs (c)(1)(iii) and (c)(2)(v) to expressly clarify that the 
allowances that were in effect when the 1988 Gas Rule became effective, 
and that were ``grandfathered'' under former paragraphs (c)(1)(v) and 
(c)(2)(v), have been terminated.
    Summary of Comments: One industry trade association commented that 
it supports the proposed changes, although it supports the removal of 
the ``grandfather'' clause prospectively. One state and STRAC support 
removing the ``grandfather'' clause.
    MMS Response: The ``grandfather'' clause was removed in the 1996 
amendment, but subsequent litigation arose regarding whether the 
removal of the ``grandfather'' clause was validly accomplished. The 
amendment made in this final rule eliminates any further question in 
this regard by clearly ending any grandfathering provision.

H. Section 206.157(f)--Transportation Allowances--Specifying Allowable 
Costs

    MMS proposed to amend section 206.157(f) in several respects to 
further clarify what costs are deductible in calculating transportation 
allowances. The proposed changes are listed individually below with 
specific comments associated with each change.
    Summary of Comments: One state commented that unused firm demand 
charges and costs of surety are indirect costs and should not be 
deductible. A

[[Page 11873]]

public interest group and an individual commented that the Government 
would suffer revenue losses from these changes. These losses would be 
caused, in their view, by allowing the gas industry to deduct new 
transportation costs that are not directly related to operating and 
maintaining a pipeline. STRAC commented that ``unused firm capacity/
firm demand charges, line loss and cost of surety'' are ``already paid 
for under the \7/8\ths interest.''
    MMS Response: The MMS will respond to these general comments below 
with respect to each specific provision.
1. Section 206.157(f)(1)--Transportation Allowances--Specifying 
Allowable Costs--Allow Unused Firm Demand Charges
    The MMS proposed to add unused firm demand charges as allowable 
transportation costs under Sec.  206.157(f)(1) to conform with the DC 
Circuit's decision in IPAA v. DeWitt, 279 F.3d 1036 (DC Cir. 2002), 
cert. denied, 537 U.S. 1105 (2003). The proposed rule also provided for 
reduction of previously reported transportation allowances whenever the 
lessee sells unused firm capacity after having deducted it as part of a 
previously reported allowance.
    Summary of Comments: Two industry trade associations and one 
producer supported this change. One state, an individual commenter, a 
public interest group, and STRAC opposed the change with respect to 
allowing unused firm demand charges.
    MMS Response: As MMS explained in the preamble to the proposed 
rule, in its 1998 rulemaking, MMS had prohibited the deduction of 
unused firm demand charges. In IPAA v. DeWitt, while the DC Circuit 
upheld every other aspect of the 1998 rulemaking, it determined that 
MMS did not demonstrate that unused demand charges were not 
transportation. Therefore it held that MMS was required to allow the 
deduction of unused demand charges. The IPAA sought review of the rest 
of the case, which was denied, but the government did not seek further 
review of that decision. The MMS therefore must change the gas rule to 
conform to the court's decision. The final rule is also intended to be 
consistent with the Federal oil valuation rule, as amended.
2. Section 206.157(f)(7)--Transportation Allowances--Specifying 
Allowable Costs--Allow Fees Paid for Actual Line Losses Under Non-
Arm's-Length Contracts
    The proposed rule specified actual line losses as a cost of moving 
production. Theoretical line losses would be allowed only in arm's-
length transportation situations.
    Summary of Comments: Two industry trade associations support the 
change. Two states and the congressional commenter oppose the proposed 
change. One state believes that line losses are indirect costs that 
result from metering differences and are very inaccurate.
    MMS Response: The MMS believes that actual line losses properly may 
be regarded as a cost of moving production. In addition, if there is 
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.
3. Section 206.157(f)(10)--Transportation Allowances--Specifying 
Allowable Costs--Allow the Cost of Securing a Letter of Credit or Other 
Surety Required by the Pipeline Under Arm's-Length Contracts
    The proposed rule would allow the cost of securing a letter of 
credit or other surety, insofar as those costs are currently allocable 
to production from Federal leases, in arm's-length transportation 
situations and are necessary to obtain the pipeline's transportation 
services.
    Summary of Comments: One industry trade association supports the 
change. Two states, STRAC, and the congressional commenter oppose the 
proposed change. One state commented that, if MMS allows a cost of 
surety, it erodes the valuation associated with the Federal 
Government's royalty interest and ``increases the profit margin 
associated to [sic] the working interest'' because this type of cost is 
a ``service fee'' that historically has not been deductible. One state 
and STRAC commented that MMS historically has not allowed service-type 
fees that are associated with the lessee's responsibility to market the 
production at no cost to the lessor and that this change should not be 
allowed.
    MMS Response: As explained in the preamble to the proposed rule, 
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. The view of state commenters and STRAC that this type 
of cost is a ``service fee'' does not address whether incurring the 
cost is necessary to transport production. Contrary to the view of one 
state and STRAC, MMS does not believe that the cost of obtaining a 
letter of credit or other surety is a cost associated with marketing 
the production. The costs necessary to market the production do not 
depend on whether a pipeline requires a letter of credit.
    As explained in the preamble to the proposed rule, in non-arm's-
length situations, MMS believes 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. The MMS therefore believes it is 
inappropriate to allow such a deduction under non-arm's-length 
transportation arrangements.

I. Section 206.157(g)--Transportation Allowances--Specifying Non-
Allowable Costs (Fees Paid to Brokers, Fees Paid to Scheduling Service 
Providers, and Internal Costs)

    Summary of Comments: Two states and STRAC supported the 
clarifications. The MMS received no comments opposing these 
clarifications.
    MMS Response: As explained in the preamble to the proposed rule, 
fees paid to brokers include 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, if such fees are 
separately identified from aggregator/marketer fees, are marketing or 
administrative costs that lessees must bear at their own expense and 
are not actual costs of transportation because, unlike the surety 
charges, the pipeline does not require that they be paid.
    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, have never 
been deductible. The final rule reaffirms this principle.

J. Other Comments on Allowable or Non-Allowable Costs

    Summary of Comments: Two industry trade associations questioned why 
``line pack'' is not an allowable transportation

[[Page 11874]]

cost. One industry trade association requested that the transportation 
costs attributable to excess carbon dioxide, where it is necessary to 
transport the carbon dioxide entrained in the main gas stream before 
disposal as a waste product, be allowable transportation costs.
    MMS Response: With respect to ``line pack,'' the commenters did not 
provide any examples in which lessees had actually been charged for 
line pack as an actual cost of transportation, nor does MMS know of any 
such situations.
    The trade association's comment regarding ``excess CO2'' 
appears to misunderstand the current rule at 30 CFR 206.157(a)(2)(i), 
which provides that no allowance may be taken for the costs of 
transporting lease production which is not royalty bearing without MMS 
approval. The ``excess CO2'' removed at a treatment plant is 
a non-royalty-bearing product. The transportation pipeline will not 
transport the gas unless the CO2 is removed. So if the 
CO2 is not removed the gas cannot be marketed. The increment 
of CO2 allowed in a transportation pipeline (e.g., 2 
percent) is a ``waste product.'' The cost of transporting the ``waste 
product'' increment is allowed as part of the cost of transporting gas, 
while the cost of transporting the non-royalty-bearing product is not. 
The location at which a lessee chooses to treat production for removal 
of CO2 is up to the lessee. If the lessee treats production 
at a location away from the lease, transporting the excess 
CO2 to that location is part of the costs of putting the 
production into marketable condition and, therefore, is not deductible.

K. Other Comments

    Summary of Comments: An industry trade association requested to be 
able to use the prior year's actual costs in the current year to 
eliminate reporting of retroactive adjustments on the Form MMS-2014. 
The association noted that companies must report estimates until 
actuals are calculated and then reverse previous lines.
    MMS Response: This comment and issues related to it are beyond the 
scope of the proposed rule, and addressing these issues would require 
initiation of new rulemaking proceedings.

III. Procedural Matters

1. Summary Cost and Royalty Impact Data

    Summarized below are the annual estimated costs and royalty impacts 
of this rule to all potentially affected groups: industry, the Federal 
Government, and state and local governments. The MMS did not receive 
any specific comments regarding the estimated costs and royalty impacts 
of this rule when it was proposed in the Federal Register July 23, 2004 
(69 FR 43944). The costs and royalty impact estimates have changed 
since the proposed rule due to further analysis.
    Of the changes being implemented under this rulemaking that have 
cost impacts, some will result in royalty decreases for industry, 
states, and MMS, and two changes will result in a royalty increase. The 
net impact of the changes will result in an expected overall royalty 
increase of $2,251,000, as itemized below.
A. Industry
    (1) No Change in Royalties--Allow Transportation Deduction for 
Unused Firm Demand Charges.
    Under this rule, industry is allowed to deduct the portion of firm 
demand charges it paid ``arm's-length'' to a pipeline, but did not use. 
Currently, following the decision of the DC Circuit in IPAA v. DeWitt, 
industry may already deduct these charges. In the proposed rule, MMS 
estimated a revenue decrease from this provision. The MMS now realizes 
that this provision is merely codifying existing law and no royalty 
change is effected by this clarification.
    (2) Net Decrease in Royalties--Increase Rate of Return in Non-
Arm's-Length Situations From 1 Times the Standard & Poor's BBB Bond 
Rate to 1.3 Times the Standard & Poor's BBB Bond Rate.
    The total transportation allowances deducted by Federal lessees 
from gas royalties for FY 2002 were approximately $103,789,000 for both 
onshore and offshore leases. 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 affiliated with the lessee. Therefore, 
we estimate that 75 percent of all gas transportation allowances are 
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 depreciation expenses and 1/3 operation, maintenance and overhead 
expenses (these are the same assumptions used in the recent threshold 
analysis for the 2004 Federal oil valuation rulemaking). Based on total 
gas transportation allowance deductions of $103,789,000 for FY 2002, 
the percentage of non-arm's-length gas transportation allowances and 
our assumptions regarding the makeup of the allowance components, the 
portion of allowances attributable to the rate of return will be 
approximately $8,649,000 ($103,789,000 x .25 x .3333). 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 will 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. However, the 
cost of the line loss is calculated based on the value of the gas 
transported, not on the cost or rate of its transportation. Therefore, 
the 0.2 percent line loss volume implies a 0.2 percent decrease in the 
royalty owed on Federal gas subject to transportation. For FY 2002, the 
royalty reported prior to allowances, for those leases in which a 
transportation allowance was reported, was approximately 
$2,506,447,000. Assuming 25 percent of that amount corresponds to gas 
that was transported under non-arm's-length transportation 
arrangements, the decrease due to line loss would be $1,253,224 
($2,506,447,000 x .25 x .002), or 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 MMS understands that the cost of a letter of credit generally 
is based on the volume of gas transported through a pipeline under 
arm's-length transportation contracts and the creditworthiness of the 
shipper. We first determined that, based on the total sales volume of 
gas from Federal onshore and offshore leases of 5,822,000,000 Mcf for 
FY 2002, approximately 4,892,000,000 Mcf was not taken as Royalty in 
Kind (RIK). Then we estimated that 80 percent of 4,892,000,000 Mcf from 
Federal onshore and offshore leases is subject to a transportation 
allowance and the average onshore and offshore royalty rate is 13.55 
percent. Therefore, the portion corresponding to the royalty percentage 
of the Federal gas sales volume subject to a transportation allowance 
will be approximately 530,000,000 Mcf (4,892,000,000 x .80 x .1355). 
Next, we assumed that 75 percent of that volume will be transported at 
arm's length, and that

[[Page 11875]]

typical letter of credit costs will be the cost of transporting 2 
months' volume (\1/6\ of the annual volume) at a rate of $0.03 per Mcf. 
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 
and gas corporations with A or higher credit ratings. Therefore, the 
net decrease in royalties will be approximately $398,000 (530,000,000 x 
.75 x \1/6\ x $0.03 x .2) annually.
    Total Net Decrease in Royalties--Industry.

$2,595,000 + $1,253,000 + 398,000 = $4,246,000.
    (4) Net Increase in Royalties--Restrict Use of FERC Tariff Charges.
    The MMS has received 94 requests to date to use FERC-approved gas 
tariffs as an exception to non-arm's-length transportation costs. When 
approved, these exceptions will continue year after year. For this 
revenue impact analysis, we assumed that 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 will be nationwide, due to 
significantly varying market conditions, location differences, and a 
myriad of tariff structures, we estimated that a reasonable discounted 
rate that will be paid under the FERC tariff will be 90 percent of the 
full tariff rate. Therefore, under the new provision, lessees will 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 annually 
($103,789,000 x .25 x .5 x .1 = $1,297,000).
    (5) Net Increase in Royalties--Eliminate ``Grandfather'' Clause.
    MMS believes that there are few instances of continuing use of 
valuation determinations that were in effect before 1988 and continued 
to be in effect under the 1988 Gas Rule. From our audit work on these 
leases for FY 2002, MMS estimates that royalties will increase under 
this rule by approximately $5,200,000 annually.
    Total Net Increase in Royalties--Industry.

$1,297,000 + $5,200,000 = $6,497,000.
B. State and Local Governments
    This rule will not impose any additional burden on local 
governments.
    States receiving a portion of royalties from offshore leases 
located within the zone defined and governed by section 8(g) of Outer 
Continental Shelf Lands Act, 43 U.S.C. 1337(g), will share in a portion 
of the increased or decreased royalties resulting from transportation 
allowances claimed by industry. To determine the impact for these 
``8(g) states,'' we used a factor of .505 (the portion of gas 
transportation allowances attributable to offshore production) 
multiplied by a factor of .0061 (the portion of offshore Federal 
revenues disbursed to states for section 8(g) leases) to arrive at a 
factor of .0030805 that we then applied to the net increases or 
decreases resulting from the calculations in paragraph A.
    Onshore states will also share in a portion of the increased or 
decreased royalties resulting from transportation allowances claimed by 
industry. To determine the impact on onshore States, we used a factor 
of .495 (the portion of gas transportation allowances attributable to 
onshore production) multiplied by a factor of .5 (the approximate 
overall portion of onshore Federal revenues disbursed to states) to 
arrive at a factor of .2475 that we then applied to the net increases 
or decreases resulting from the calculations in paragraph A.
    (1) Net Decrease in Royalties--Allow Transportation Deduction for 
Unused Firm Demand Charges.
    There is no impact.
    (2) Net Decrease in Royalties--Increase Rate of Return in Non-
Arm's-Length Situations From 1 Times the Standard & Poor's BBB Bond 
Rate to 1.3 Times the Standard & Poor's BBB Bond Rate.

$2,595,000 x .0030805 = $8,000 (for OCS 8(g) states) + $2,595,000 x 
.2475 = $642,000 (for onshore states) = $650,000.

    (3a) Net Decrease in Royalties--Allow Line Loss as a Component of a 
Non-Arm's-Length Transportation Allowance.

$1,253,000 x .0030805 = $4,000 (for OCS 8(g) states) + $1,253,000 x 
.2475 = $310,000 (for onshore states) = $314,000.

    (3b) Net Decrease in Royalties--Allow the Cost of a Letter of 
Credit as a Component of an Arm's-Length Transportation Allowance.

$398,000 x .0030805 = $1,000 (for OCS 8(g) states) + $398,000 x .2475 = 
$99,000 (for onshore states) = $100,000.

    Total Net Decrease in Royalties--States.

$650,000 + $314,000 + $100,000 = $1,064,000.

    (4) Net Increase in Royalties--Restrict Use of FERC Tariff Charges.

$1,297,000 x .0030805 = $4,000 (for OCS 8(g) states) + $1,297,000 x 
.2475 = $321,000 (for onshore states) = $325,000.

    (5) Net Increase in Royalties--Eliminate ``Grandfather'' Clause.

$5,200,000 x .5 = $2,600,000 (for onshore states only).

    Total Net Increase in Royalties--States.

$325,000 + $2,600,000 = $2,925,000.

    The total impact on all states will be a revenue increase of 
approximately $1,861,000 ($2,925,000-$1,064,000) annually.
C. Federal Government
    The Federal Government, like the states, will be affected by a net 
overall increase in royalties as a result of the changes to the 
regulations governing transportation allowance computations and the 
changes effected by Sec.  206.157(c), eliminating the ``grandfather'' 
clause. In fact, the royalty increase experienced by the Federal 
Government will be the difference between the total increased royalty 
obligations on the industry and the portion of the royalty increase 
that benefits the states. In other words, the royalty increase to 
industry will be shared proportionately between the states and the 
Federal Government as computed below.
    (1) Net Decrease in Royalties--Allow Transportation Deduction for 
Unused Firm Demand Charges.

    There is no impact.
    (2) Net Decrease in Royalties--Increase Rate of Return in Non-
Arm's-Length Situations From 1 Times the Standard & Poor's BBB Bond 
Rate to 1.3 Times the Standard & Poor's BBB Bond Rate.

$2,595,000 (total decrease)--$650,000 (states' share) = $1,945,000.

    (3a) Net Decrease in Royalties--Allow Line Loss as a Component of a 
Non-Arm's-Length Transportation Allowance.

$1,253,000 (total decrease)-$314,000 (states' share) = $939,000.

    (3b) Net Decrease in Royalties--Allow the Cost of a Letter of 
Credit as a Component of an Arm's-Length Transportation Allowance.

$398,000 (total decrease)-$100,000 (states' share) = $298,000.

    Total Net Decrease in Royalties--Federal Government.

$1,945,000 + $939,000 + $298,000 = $3,182,000.

    (4) Net Increase in Royalties--Restrict use of FERC Tariff Charges.


[[Page 11876]]


$1,297,000 (total increase) - $325,000 (states' share) = $972,000.

    (5) Net Increase in Royalties--Eliminate ``Grandfather'' Clause.

$5,200,000 (total increase)-$2,600,000 (states'' share) = $2,600,000.

    Total Net Increase in Royalties--Federal Government.

$972,000 + $2,600,000 = $3,572,000.

    The net impact on the Federal Government will be a royalty increase 
of approximately $390,000 ($3,572,000-$3,182,000) annually.
D. Summary of Costs and Royalty Impacts 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
------------------------------------------------------------------------
                                                        Annual costs and
                                                       royalty increases
                     Description                           or royalty
                                                           decreases
------------------------------------------------------------------------
A. Industry:
    (1) Royalty Decrease--Allowable Transportation           -$4,246,000
     Deductions (1-3)................................
    (2) Royalty Increase--Restrict use of FERC Tariff          6,497,000
     Charges and Eliminate ``Grandfather'' Clause (4-
     5)..............................................
    (3) Net Expected Change in Royalty Payments from           2,251,000
     Industry........................................
B. State and Local Governments:
    (1) Royalty Decrease--Allowable Transportation            -1,064,000
     Deductions (1-3)................................
    (2) Royalty Increase `` Restrict use of FERC               2,925,000
     Tariff Charges and Eliminate ``Grandfather''
     Clause (4-5)....................................
    (3) Net Expected Change in Royalty Payments to             1,861,000
     States..........................................
C. Federal Government:
    (1) Royalty Decrease--Allowable Transportation            -3,182,000
     Deductions (1-3)................................
    (2) Royalty Increase--Restrict use of FERC Tariff          3,572,000
     Charges and Eliminate ``Grandfather'' Clause (4-
     5)..............................................
    (3) Net Expected Change in Royalty Payments to               390,000
     Federal Government..............................
------------------------------------------------------------------------

2. Regulatory Planning and Review, Executive Order 12866

    Under the criteria in Executive Order 12866, this 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 rule 
because it raises novel legal or policy issues.
    1. This 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 rule will not create inconsistencies with other agencies' 
actions.
    3. This rule will not materially affect entitlements, grants, user 
fees, loan programs, or the rights and obligations of their recipients.
    4. This rule will raise novel legal or policy issues.

3. Regulatory Flexibility Act

    The Department of the Interior certifies this 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.). 
The rule applies primarily to large, integrated producers who transport 
their natural gas production through their own pipelines or pipelines 
owned by major natural gas transmission providers.
    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.

4. Small Business Regulatory Enforcement Fairness Act (SBREFA)

    This rule is not a major rule under 5 U.S.C. 804(2), the Small 
Business Regulatory Enforcement Fairness Act. This rule:
    1. Does not have an annual effect on the economy of $100 million or 
more. See the above 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.

5. Unfunded Mandates Reform Act

    In accordance with the Unfunded Mandates Reform Act (2 U.S.C. 1501 
et seq.):
    1. This rule will not significantly or uniquely affect small 
governments. Therefore, a Small Government Agency Plan is not required.
    2. This 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.''

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

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

[[Page 11877]]

7. Federalism, Executive Order 13132

    In accordance with Executive Order 13132, this 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 rule will not alter any lease 
management or royalty sharing provisions. It will determine the value 
of production for royalty computation purposes only. This rule will not 
impose costs on states or localities.

8. Civil Justice Reform, Executive Order 12988

    In accordance with Executive Order 12988, the Office of the 
Solicitor has determined that this 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.

9. Paperwork Reduction Act of 1995

    This rulemaking does not contain new information collection 
requirements or significantly change existing information collection 
requirements; therefore, a submission to OMB is not required. The 
information collection requirements referenced in this 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. Under the proposed rule (69 
FR 43944, July 23, 2004), we asked for comments regarding any 
information collection burdens that would arise under a new provision 
at Section 206.157(b)(5) that would allow lessees an exception 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. We did not receive any comments regarding 
information collection burdens on that specific provision.

10. National Environmental Policy Act (NEPA)

    This 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.

11. 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. This rule does 
not apply to Indian leases. However, it is theoretically possible that 
this rule might have a very small impact on the competitiveness of 
Indian leases in situations where an Indian lease is not in an index 
zone and the lessee is affiliated with the pipeline that transports the 
Indian lease production. It is only in those situations that the lessee 
would have to calculate actual transportation costs using different 
provisions than prescribed for Federal leases in this final rule. The 
MMS anticipates that such situations will be extremely rare.

12. 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 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 rule otherwise impact energy supply, distribution, or use.

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

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

14. 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.  206.157 Determination of Transportation Allowances. (5) 
What is the purpose of this part? (6) Is the description of the rule in 
the Supplementary Information section of the preamble helpful in 
understanding the rule? (7) 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.

List of Subjects in 30 CFR Part 206

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

    Dated: February 2, 2005.
Rebecca W. Watson,
Assistant Secretary for Land and Minerals Management.

0
For the reasons set forth in the preamble, part 206 of title 30 of the 
Code of Federal Regulations is amended as follows:

PART 206--PRODUCT VALUATION

0
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, 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.


0
2. In Sec.  206.150, paragraph (b) is revised to read 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

[[Page 11878]]

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.
* * * * *

0
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 10 through 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.
* * * * *

0
4. Section 206.157 is amended as follows:
0
A. Paragraph (b)(2)(v) is revised;
0
B. Paragraph (b)(5) is revised;
0
C. Paragraph (c) is revised;
0
D. Paragraphs (f) introductory text, (f)(1), and (f)(7) are revised and 
paragraph (f)(10) is added; and
0
E. The word ``and'' at the end of paragraph (g)(4) is removed, 
paragraph (g)(5) is revised, and new paragraphs (g)(6) through (g)(8) 
are added.
0
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 & Poor's BBB rating. The BBB rate must be the 
monthly average rate as published in Standard & 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 filed with the Federal 
Energy Regulatory Commission (FERC) or a state regulatory agency, that 
FERC or the state regulatory agency has permitted to become effective, 
and
    (B) Third parties are paying prices, including discounted 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 lesser 
of the volume-weighted average of the rates paid by the third parties 
under arm's-length transportation contracts during that production 
month or the non-arm's-length payment by the lessee to the pipeline.
    (iii) 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 the tariff remains in effect and third parties paid such 
rates, for up to five successive production months. You must use the 
non-arm's-length payment by the lessee to the pipeline if it is less 
than the volume-weighted average of the rates paid by third parties 
under arm's-length 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.

[[Page 11879]]

    (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. 05-4515 Filed 3-9-05; 8:45 am]
BILLING CODE 4310-MR-P