[Federal Register Volume 69, Number 87 (Wednesday, May 5, 2004)]
[Rules and Regulations]
[Pages 24959-24979]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 04-10083]


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DEPARTMENT OF THE INTERIOR

Minerals Management Service

30 CFR Part 206

RIN 1010-AD04


Federal Oil Valuation

AGENCY: Minerals Management Service (MMS), Interior.

ACTION: Final rule.

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SUMMARY: MMS is amending the existing regulations governing the 
valuation of crude oil produced from Federal leases for royalty 
purposes, and related provisions governing the reporting thereof. The 
current regulations became effective on June 1, 2000.
    These amendments primarily affect which published market prices are 
most appropriate to value crude oil not sold at arm's length and what 
transportation deductions should be allowed.

DATES: Effective date: July 6, 2004.

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.
    The principal authors of this rule are Mary A. Williams, Kenneth R. 
Vogel, and James P. Morris of Minerals Revenue Management, MMS, and 
Martin C. Grieshaber of Policy and Management Improvement, MMS, and 
Geoffrey Heath of the Office of the Solicitor, Department of the 
Interior.

SUPPLEMENTARY INFORMATION:

I. Background

    The MMS is amending the existing regulations at 30 CFR 206.100 et 
seq., governing the valuation of crude oil produced from Federal leases 
for royalty purposes, and related provisions governing the reporting 
thereof. The current regulations became effective on June 1, 2000 (June 
2000 Rule).
    After conducting several public workshops, MMS issued a proposed 
rule that was published in the Federal Register on August 20, 2003 (64 
FR 50088). The original comment period for this proposed rule closed on 
September 19, 2003. However, MMS received requests to extend the 
comment period and on September 26, 2003, MMS reopened the comment 
period until November 10, 2003 (68 FR 55556).
    The amendments do not alter the basic structure or underlying 
principles of the June 2000 Rule. In proposing these amendments, the 
Department of the Interior reaffirmed that the value for royalty 
purposes of crude oil produced from Federal leases is the value at or 
near the lease. However, in determining value at the lease of 
production not sold under an arm's-length contract, MMS is not 
restricted to a comparison to arm's-length sales of other production 
occurring in the field or area. MMS may begin with a ``downstream'' 
price or value, and determine value at the lease by deducting the costs 
of transporting oil to downstream sales points or markets, or by making 
appropriate adjustments for location and quality.
    Federal lessees are not obligated to sell crude oil downstream of 
the lease. Lessees are at liberty to sell production at or near the 
lease, even if selling downstream might have resulted in a higher 
royalty value for the production than selling it at the lease. If 
lessees do choose to sell downstream, the choice to sell downstream 
does not make otherwise non-deductible costs deductible (for example, 
marketing costs). See Independent Petroleum Association of America, et 
al. v. DeWitt, 279 F.3d 1036 (DC Cir. 2002), cert. denied sub nom., 
Independent Petroleum Association of America, et al. v. Watson, 537 
U.S. 1105 (2003). In addition, MMS may choose to use downstream values 
when a lessee sells to an affiliate at or near the lease.

II. Comments on the Proposed Rule

    Public comments received in response to the proposed rule favored 
most of the proposed changes. MMS received some negative comments 
regarding the proposed method for valuing California and Alaska crude 
oil, some of the specifications of allowable transportation costs, and 
changing the rate of return on undepreciated capital investments in 
calculating non-arms-length transportation allowances. We will group 
the comments received and the MMS responses generally according to the 
order of the substantive provisions of the rule (with related changes 
to definitions), with discussion of miscellaneous technical changes 
thereafter. MMS received comments on the proposed rule from 27 
respondents.

A. Changing to NYMEX-Based Valuation and Determining the NYMEX Price To 
Use for Valuation--Sec.  206.103

    MMS proposed using New York Mercantile Exchange (NYMEX)-based value 
with a roll as one of the measures of value for production not sold at 
arm's length in all areas except for California, Alaska, and the Rocky 
Mountain Region where MMS proposed to use NYMEX-based value without the 
roll. In the Rocky Mountain Region, NYMEX-based value without the roll 
would be used as the revised third benchmark (proposed to be 
redesignated as Sec.  206.103(b)(3)). The base NYMEX price would be 
adjusted for location and quality differentials and actual 
transportation costs back to the lease.
    Summary of Comments: Fifteen respondents submitted comments on the 
use of NYMEX pricing. There were several comments about our rationale 
for changing from a spot market index price to NYMEX and adjusting for

[[Page 24960]]

location and quality differentials. Industry commenters generally 
supported using NYMEX, although they believe that spot market index 
prices are a workable starting point for valuation of oil not sold at 
arm's length. Some industry commenters believe that the NYMEX calendar 
month average is closer to the actual value of oil produced in the 
Rocky Mountain Region than the West Texas Intermediate (WTI) (Cushing, 
Oklahoma) spot prices prescribed as the third benchmark value in the 
June 2000 Rule. Industry comments were not opposed to retaining Alaska 
North Slope (ANS) spot prices as the basis for valuing oil produced in 
California and Alaska.
    Industry commenters generally believe that the roll should not 
apply to oil produced in California, Alaska, or the Rocky Mountain 
Region. One industry group further suggested that the roll should not 
apply to oil produced in the Western Gulf of Mexico, or the San Juan 
Basin, or any other area that does not have a market center where 
physical exchanges occur between that market center and Cushing.
    Industry believes that MMS should choose whether to include 
weekends and holidays in the calculation of the average NYMEX price, 
and is comfortable with MMS's choice to exclude them. Industry 
suggested that the three benchmarks and the alternative valuation 
provision for the Rocky Mountain Region are adequate.
    State comments on the use of NYMEX were mixed. Two States supported 
the use of NYMEX. One State does not agree with using NYMEX as the 
third benchmark for the Rocky Mountain Region, and believes that non-
arm's-length royalties should be determined by the affiliate's 
downstream sales price. The California State Controller's Office (SCO) 
strongly objected to using the adjusted NYMEX price for California and 
suggested retaining ANS spot prices. Several members of the California 
congressional delegation concurred with the California SCO comments.
    MMS Response: MMS believes that, at this time, NYMEX futures prices 
probably represent a more reliable and better assessment of current oil 
values than spot prices. Use of the NYMEX price as the basis for 
royalty value has several advantages, not the least of which is the 
fact that the volume of transactions and the number of participants is 
so large that, at least theoretically, no one entity could manipulate 
the resultant price. This is an issue partly because of the recent 
publicity and questions about the information provided to spot price 
reporting services and the effect such potentially inaccurate 
information has on spot prices in general. In addition, there is only 
one NYMEX price, and it is available from any number of sources. There 
would be no question about the correct publication to use to obtain the 
applicable index price.
    Further, various questions have arisen about the timing of 
application of index prices. Published spot prices for specific months 
generally represent the market's assessment of prices for crude oil 
delivered during that month, but determined between the 26th day of the 
month 2 months prior to the delivery month and the 25th day of the 
month immediately preceding the delivery month. MMS has reviewed the 
correlation between several public indicia of crude oil prices (e.g., 
trading month spot prices, NYMEX prices, etc.) and the values actually 
used in paying royalties to MMS on crude oil sold at arm's length. This 
review demonstrated that calendar-month NYMEX prices (applying the 
roll, as discussed below, to production from areas outside the Rocky 
Mountain Region, California, and Alaska) have the highest correlation 
to reported arm's-length sales values of any publicly-available 
indices.
    The June 2000 Rule used spot market index prices determined for the 
trading period that is closest to concurrent with the production month. 
However, this period is not consistent with the way industry does 
business. First, as explained above, the published spot market index 
price relevant to spot market deliveries during the production month is 
actually the price published the month before the month used to value 
the current month's production in the existing rule. For example, while 
the price determined in the period January 26 to February 25 may be the 
correct timing for spot sales at the market center for deliveries in 
March, that price may not reflect prices received in March for actual 
arm's-length sales by producers that are often made more 
contemporaneously with production. Second, the spot price used in the 
existing rule is not the price used for spot sales, but occurs 1 month 
later. It overlaps, but is not the same as, the production month. A 
price for production in March should be the most current and accurate 
information that a purchaser or seller would have at the time of 
production. The NYMEX prices are available on a real time basis to 
traders and, therefore, are the ones used most commonly to determine 
the base price of oil during the month of production. Comments received 
concur with the proposition that using the calendar month average of 
the daily NYMEX settlement prices will correlate more closely to prices 
received in the current production month than the index prices used in 
the existing rule.
    A recent MMS review compared valuation of a common crude oil grade 
(Eugene Island) produced in the Gulf of Mexico using both the calendar 
month NYMEX price, with a roll (discussed below), and the spot market 
index price provisions of the existing crude oil valuation rule that 
became effective on June 1, 2000. The review found that the calendar 
month NYMEX price (with the roll) is advantageous to the public when 
futures prices in the out months are lower going forward (when the 
market is in ``backwardation''). Existing spot market index price 
provisions, or the use of NYMEX without the roll, are advantageous to 
the public when futures prices in the out months are higher going 
forward (when the market is in ``contango''). Using historical NYMEX 
data since the NYMEX oil market began in 1986, prices in the out months 
have been lower going forward approximately 60 percent of the time. 
Thus, taking a conservative and long-term approach to royalty valuation 
supports use of the NYMEX price with the roll.
    MMS proposed to exclude weekends and holidays from the calculation 
of the average NYMEX price because NYMEX does not publish prices on 
those days. Commenters generally supported that choice and said that 
the agency should clearly choose either exclusion or inclusion. In 
addition, the WTI differential (based on WTI spot market prices) 
excludes weekends and holidays. In the final rule, MMS is adopting the 
proposal, and the rule excludes weekends and holidays from the 
calculation of the average NYMEX price.
    MMS proposed the average NYMEX price as the basis for valuing oil 
produced in California and Alaska that is not sold at arm's length. MMS 
believes that choosing either ANS spot prices or NYMEX prices would 
lead to substantively the same result in royalty valuation over time. 
Publications that publish ANS spot prices also publish differentials 
between ANS and WTI crude oil at Cushing. The spot price for WTI at 
Cushing is similar to the NYMEX price. Thus, the NYMEX price adjusted 
by the differential between ANS and WTI at Cushing would yield a result 
very similar to ANS spot prices. After consideration of comments from 
the California SCO and related congressional comments, and because 
using ANS spot prices will be somewhat simpler than using NYMEX prices 
minus the WTI-ANS differential, MMS

[[Page 24961]]

has decided to retain adjusted ANS spot pricing for valuing crude oil 
produced from Federal leases in California and Alaska.
    As a result of moving to NYMEX pricing generally but retaining ANS 
spot pricing for oil produced in California and Alaska, the references 
to ``index price'' in several sections of the existing rule are 
replaced by a reference to ``ANS spot price.''
    The comments received supported MMS's proposal to use NYMEX prices 
as the third benchmark for valuing oil produced from leases in the 
Rocky Mountain Region that is not sold at arm's length if the lessee 
does not have an approved tendering program. As in the proposed rule, 
the final rule retains the other three benchmarks for the Rocky 
Mountain Region from the existing rule.
    MMS proposed applying a roll as an adjustment to the initial NYMEX 
prices for oil produced from leases outside the Rocky Mountain Region, 
California, and Alaska. One of the reasons that MMS proposed use of the 
roll was its own experience in selling crude oil taken as royalty in 
kind in the Gulf of Mexico under 43 U.S.C. 1353 and sold competitively 
to small refiners. MMS found that a substantial portion of the crude 
oil produced in the Gulf, and sold at arm's length was sold on the 
basis of a NYMEX price methodology, including the roll. MMS found that 
use of the roll resulted in increased return to the public on oil taken 
in kind and sold.
    The roll is a commonly used measure of the trend of NYMEX prices 
for future deliveries in those areas. Prices reported for futures 
contracts on the NYMEX are not limited to deliveries in the prompt 
month as defined in this rule. Rather, trades could be made in March 
2003 for deliveries in April 2003 or in several subsequent months. Due 
to the fact that the NYMEX prices are future price estimates and, 
therefore, inherently reflect increases or decreases in prices based 
upon expected trends, an adjustment to such estimates may be 
appropriate to extrapolate back to current price estimates, upon which 
royalty calculations are based. This adjustment factor is the roll, 
which is added to the initial NYMEX price when prices for the out 
months are in backwardation (to correct for the fact that the current 
price should be higher than the future price in this circumstance), and 
subtracted from the initial NYMEX price when prices for the out months 
are in contango (to correct for the fact that the current price should 
be lower than the future price in this circumstance). MMS proposed to 
add the roll to the initial NYMEX price used as the basis for royalty 
valuation, except for leases in the Rocky Mountain Region, California, 
and Alaska. As explained in the preamble to the proposed rule, the roll 
is not commonly used in transactions involving oil produced in the 
Rocky Mountain Region, California, or Alaska. For California and 
Alaska, the roll is irrelevant in the final rule because MMS is 
retaining ANS spot prices as the basis for royalty value. Commenters 
generally agreed that the roll should not be applied to oil produced in 
the Rocky Mountain Region, California, or Alaska.
    MMS does not agree with the suggestion of one commenter to apply 
the roll to production from the Gulf of Mexico that goes to market 
centers from which there are trades to Cushing, but not to production 
that goes to market centers from which there are not trades to Cushing. 
Determining which production from which leases goes to which market 
centers, and whether it is common for those market centers to have 
trades to Cushing, would add substantial administrative burden and cost 
to both royalty payors and the Government. Further, there was no 
explanation of why this alleged difference was relevant to applying the 
roll.
    The proposed use of the roll also necessitated a corresponding 
proposed change to the definition of ``trading month.'' In Sec.  
206.101 of the existing rule, ``trading month'' is defined in terms of 
spot market sales. MMS proposed to change the definition of ``trading 
month'' to conform with NYMEX definitions and practice. It will be used 
only to calculate the roll. MMS received no comments opposing that 
change, and is adopting it in the final rule.
    Based on the comments received, the final rule prescribes the NYMEX 
price with a roll as the royalty valuation basis for production from 
areas outside of the Rocky Mountain Region, California, and Alaska that 
is not sold at arm's length, and NYMEX with no roll as the third 
benchmark for production from the Rocky Mountain Region.
    Additionally, in Sec.  206.103(b), the paragraphs for the four 
benchmarks in the Rocky Mountain Region are renumbered (b)(1) through 
(b)(4) to correspond with the benchmark numbers as proposed. Industry 
supported the clarification.
    While MMS expects the basic operation of the NYMEX market to be the 
same for the foreseeable future, it is not so clear that the roll will 
be a permanent feature of the marketplace. When MMS believes that using 
the roll is no longer a common industry practice, the MMS Director may 
terminate the use of the roll. However, the MMS Director may terminate 
the use of the roll only at the end of each 2-year period following the 
effective date of this rule, through notice published in the Federal 
Register no later than 60 days before the end of such 2-year period. 
Further, MMS also will have the option to redefine how the roll is 
calculated to comport with changes in industry practice, through notice 
published in the Federal Register no later than 60 days before the end 
of each 2-year period. MMS will explain its rationale when it publishes 
the notice. MMS believes that this flexibility is appropriate so that 
the valuation standards more closely reflect market developments. As 
proposed, MMS is adding at Sec.  206.103(c)(2) the option to terminate 
or modify the roll at the end of each 2-year period after the effective 
date of this rule.
    MMS sought comments in the proposed rule on allowing the use of the 
NYMEX price to value oil sold at arm's length in multiple sales 
downstream of the lease where the lessee does not first transfer to an 
affiliate and where ``tracing'' the production from the lease or unit 
to the specific sale is burdensome. MMS received positive comments from 
industry concerning the option to use an index-based value when a 
producer has numerous arm's-length sales downstream of the lease. 
Allowing producers to use NYMEX prices for these transactions might 
alleviate some administrative burden. However, we believe that royalty 
payments should be based on actual sale prices whenever possible. Also, 
under the existing regulations, producers have the option of 
petitioning MMS for alternative valuation procedures if they believe 
the administrative burden of tracing sales is excessive. In fact, MMS 
received requests for alternative valuation approvals to alleviate the 
tracing burden and is in the process of finalizing the requests. Based 
on these facts, MMS believes the existing regulations are working and 
do not need to be modified.

B. Adjusting the NYMEX Price for Transportation Costs and Location and 
Quality Differentials--Sec. Sec.  206.109 and 206.112

1. Adjustments of NYMEX Prices to Market Centers Generally and Use of 
WTI Differentials
    MMS proposed to adjust the base NYMEX price for location and 
quality differentials and actual transportation costs back to the 
lease. Using NYMEX prices necessitates adjusting values

[[Page 24962]]

between market centers and Cushing (the location of the NYMEX price), 
because the value of the commodity (oil) varies by location and 
quality. Crude oil will be worth more the closer it is to 40 degrees 
API gravity, and the nearer it is located to markets or refineries. To 
adjust for the differences in location and quality, MMS proposed to use 
actual arm's-length exchange agreements, which are the market's 
valuation of the difference. MMS also proposed to allow the use of 
published differentials between the market center and Cushing when 
lessees do not actually exchange oil to Cushing at arm's length. In 
that connection, MMS proposed to add a definition of a new term, ``WTI 
differential,'' which is the term for that published differential. MMS 
also proposed to amend the definition of ``MMS-approved publication'' 
to include the WTI differential.
    Summary of Comments: Ten respondents provided comments on adjusting 
the NYMEX price for transportation costs and location and quality 
differentials. The California SCO objected to adjusting the NYMEX price 
for quality and location in California by using the difference between 
the WTI spot price and the market center spot prices for crude oil. 
Additionally, the California SCO asserted that using a WTI differential 
fails to account for uplift in value due to location and gives industry 
a lower price. Another State believes that differentials should be 
allowed only if they are reasonable and actually incurred.
    Industry commenters believe that requiring lessees to calculate a 
weighted-average arm's-length differential between a market center and 
Cushing could result in an unnecessary administrative burden and 
suggested that lessees should be allowed to use published WTI 
differentials in lieu of calculating their own location and quality 
differentials. Comments received from one trade publication indicated 
that restricting to a 2-year period the ability of lessees to change 
from one approved publication for WTI differentials to another is 
fundamentally anti-competitive. The commenter suggested allowing 
companies to choose a new publication every 90 days.
    One commenter observed that there is a difference between the basis 
on which the WTI differential is calculated and the basis on which the 
NYMEX price is calculated. The commenter believed that this would lead 
to an inaccuracy in the adjustments to the NYMEX price. The concern 
arose principally because the WTI differential is the basis for 
adjusting the NYMEX price between the market center and Cushing (the 
location of the NYMEX price) if the lessee does not have an exchange 
agreement between the market center and Cushing. Additionally, the same 
commenter expressed concern that this difference would affect the use 
of the roll, because the prices incorporated in the roll calculation 
would all be determined on different basis months from the WTI 
differential that is used to adjust the NYMEX price.
    MMS Response: As explained above, adopting the NYMEX price as the 
basis (or, in the Rocky Mountain Region, an alternative basis) for 
royalty valuation for oil produced from leases in areas other than 
California and Alaska and not sold at arm's length requires an 
additional adjustment beyond those in the current rule because the 
NYMEX price is defined only at Cushing for light sweet crude oil. 
Therefore, differentials from Cushing to other market centers are 
necessary. These differentials can be both positive and negative, 
depending on the quality and location of the alternative crude oil. 
They will also vary from month to month depending on relative market 
forces, e.g. tanker shortages in the Gulf, pipeline problems in 
Cushing, etc.
    Under the final rule, the average of the daily NYMEX settlement 
prices published during the calendar month of production (including the 
roll, if applicable) at Cushing is adjusted to the market center by the 
differentials derived from the lessee's actual arm's-length exchange 
agreements between the market center and Cushing applicable to 
production during the production month. However, MMS believes that many 
lessees do not have arm's-length exchange agreements, for significant 
volumes of the oil they own at market centers, between Cushing and each 
market center to which they transport or exchange crude oil. If the 
lessee does not have arm's-length exchange agreements between a 
particular market center and Cushing for at least 20 percent of the oil 
it owns at that market center (as discussed further below), the 
adjustment to Cushing for the oil that is not exchanged at arms-length 
between that market center and Cushing would be the WTI published 
differential. (For the less than 20 percent of the lessee's oil that is 
exchanged at arm's-length between that market center and Cushing, the 
lessee will use the differential derived from the arm's-length exchange 
agreement(s).) If the lessee has arm's-length exchange agreements for 
more than 20 percent of the oil it owns at that market center, it may 
use the arm's-length differential for all of its oil at that market 
center. The lessee would then calculate a further adjustment from the 
market center to the lease.
    MMS does not believe that it would be the best choice to allow 
lessees to use WTI differentials in lieu of calculating their own 
location and quality differentials when they have significant arm's-
length exchanges. If actual arm's-length data is available, MMS 
believes that is preferable to using a published differential and more 
accurately represents the actual value of the lessee's oil.
    With respect to the comment regarding the difference between the 
basis on which the WTI differential is calculated and the basis on 
which the NYMEX price is calculated, we recognize that the WTI 
differential is the average of the daily high and low differentials 
published for each day for which price publications perform surveys for 
deliveries during the production month, calculated over the number of 
days on which those differentials are published (excluding weekends and 
holidays). For a given delivery month, the industry trade publications 
perform their price surveys for the WTI spot market price and determine 
differentials from the 26th day of the second month before the delivery 
month to the 25th day of the month preceding the delivery month. For 
the same delivery month, the NYMEX price, in contrast, is calculated on 
a different basis. As defined in the final rule, the NYMEX price is the 
calendar month of production average of the daily NYMEX settlement 
prices. MMS knows of no more contemporaneous published value that it 
could use that might give more accurate market differences.
    MMS understands that the bases for calculating the WTI differential 
and the NYMEX price (and the roll) are not identical. However, as 
explained above, MMS believes that using the calendar month average 
NYMEX price is the most accurate measure of the base price of oil 
because it accounts for all the contemporaneous information available 
to traders during the production month. MMS also believes that using 
the WTI differential applicable to deliveries in the production month 
is the most accurate market measure of the expected difference in value 
between the market centers and Cushing.
    MMS believes that over time, marginal losses from adjustments to 
the NYMEX price due to the difference in basis between the NYMEX price 
and the WTI spot market price (and, therefore, the WTI differentials) 
will be offset by marginal gains from those adjustments, and that the 
net effect should be immaterial. MMS believes these

[[Page 24963]]

differences are not as important as the gain in public confidence from 
the use of NYMEX prices, which are less likely to be manipulated than 
index prices and are more easily obtained from a number of non-
proprietary sources. Additionally, WTI differentials are not the 
preferred method of calculating the adjustment from Cushing to a market 
center; under the regulation they are to be used only when a lessee 
does not have significant actual arm's-length exchanges.
    Changing from spot market index price-based valuation to NYMEX-
based valuation and adding a definition for ``WTI differential'' also 
require a revision in the definition of ``MMS-approved publication.'' 
Under the existing rule, the term ``MMS-approved publication'' referred 
to which publications of spot market index price MMS would accept. 
Under the final rule, the term now refers to the publications MMS 
approves for determining WTI differentials and ANS spot prices (because 
ANS spot market pricing is retained for production from leases in 
California and Alaska).
    MMS does not agree with the comment that lessees should be able to 
choose a new publication once every 90 days. In the final rule, 
Sec. Sec.  206.103(a)(4) and 206.112(b)(2) do not permit lessees to 
choose an MMS-approved publication for ANS spot market prices or WTI 
differentials for any period less than 2 years, which is consistent 
with current practice. Using any period less than 2 years may be viewed 
as being more prone to market manipulation to the benefit of the 
lessee.
2. Adjustments to NYMEX Prices for Crude Oil Produced From Leases in 
the Rocky Mountain Region and California
    MMS proposed adding a market center at Guernsey, Wyoming, for sweet 
crude oil produced from Federal leases in Wyoming, and requested 
comments regarding alternative valuation procedures, including 
differentials, in valuing sour crude produced from Federal leases in 
Wyoming. With regard to Wyoming sour grades, MMS asked whether it would 
be useful to include a market center for valuation of sour crude 
produced in the Rocky Mountain Region at Hardisty, Alberta, Canada (at 
which spot market prices for sour crude are published in trade 
publications), and adjust the Hardisty price for the cost of 
transportation from Casper, Wyoming (a typical delivery point) to 
Hardisty and from the lease to Casper. MMS also proposed adding 
possible market centers at Kern River for valuing San Joaquin Heavy 
produced from Federal leases in California and at Hynes Station on Line 
63 for San Joaquin Light produced from Federal leases in California.
    Summary of Comments: Wyoming opposed the suggested use of spot 
prices from Hardisty, Alberta, Canada, stating that Hardisty prices 
would be less accurate than using NYMEX prices at Cushing. The State 
also believed that the use of WTI differentials in general is not 
appropriate because they (like spot prices) potentially are susceptible 
to manipulation. The California SCO believed that the use of Hynes 
Station and Kern River as market centers would not increase accuracy in 
valuing production from Federal leases in California for Federal 
royalties.
    Industry appeared to agree that there was no need to add Hardisty 
or Guernsey as new market centers. The two industry publications that 
submitted responses suggested that should MMS decide to use prices from 
Hardisty, Alberta, Canada, then their publications be utilized. 
Industry further recommended that MMS consider application of market 
center differentials such as Kern River and Line 63 to the ANS spot 
price to establish location and quality differentials between Long 
Beach and other market centers, should MMS decide to retain ANS pricing 
for Alaska and California production.
    MMS Response: MMS agrees with the comments regarding the use of 
prices from Hardisty, Alberta, Canada, and Guernsey, Wyoming, and is 
not including either Hardisty or Guernsey as a market center at the 
present time. Using Hardisty as a market center would create a number 
of difficulties involved in making the adjustments back to the leases. 
MMS also agrees with the California SCO that the use of Kern River and 
Line 63 will not lead to improved accuracy at this time because of the 
apparently continued small volumes reported at those locations. Lessees 
who do not have their own exchanges of production from leases in the 
Rocky Mountain Region to Cushing, or of production from leases in 
California to Long Beach or San Francisco, may make proposals to MMS 
for adjustments.
3. Adjusting Values Between the Lease and the Market Center
    The proposed rule retained the basic principles in the existing 
rule of adjusting value between the market center and the lease for 
location and quality and actual transportation costs. The proposed rule 
included two changes. First, the proposed rule (at Sec.  206.112(b)) 
included a provision that if you transport or exchange (or both 
transport and exchange) at least 20 percent, but not all, of your oil 
produced from a lease to a market center, you must use the weighted 
average of the adjusted values of that oil to value oil not transported 
or exchanged to the market center. Second, the proposed rule deleted 
the provision (at existing Sec.  206.112(c)) that allowed lessees to 
use market center values at locations other than market centers 
(primarily refineries).
    MMS also proposed that if you transport your oil from the lease to 
a market center, and your oil has a higher or lower gravity and a 
higher or lower sulfur content than the crude oil for which a price is 
published at the market center, you should make an adjustment for 
quality even though you have no existing exchange agreements or quality 
banks. MMS proposed that in such circumstances, you would use 
appropriate posted price gravity tables to adjust the value of your 
produced crude for gravity differences from the market center benchmark 
crude, and use a factor of 2.5 cents per one-tenth percent difference 
in sulfur content to adjust for quality when you have neither exchange 
agreements nor quality banks to fully adjust the quality of your oil at 
the market center. MMS based this factor on our understanding of common 
sulfur bank adjustments for California.
    Summary of Comments: Three respondents submitted comments on what 
adjustments and transportation allowances apply when valuing production 
using index pricing. An industry respondent agreed with the proposal to 
have a lessee base its adjustment for the portion of its production 
that does not go to the market center (e.g., goes to a refinery) on the 
portion that goes to the market center, when it amounts to at least 20 
percent of production. Industry commenters believed that the proposed 
sulfur adjustment was inadequate, and that it should be between $.50 
and $1.00 per percent.
    MMS Response: MMS made extensive changes to this section to clarify 
how and when to apply location and quality differentials and 
transportation allowances when calculating royalty value. MMS has 
changed this section to first show (in Sec.  206.112(a)) how 
adjustments should be made between the lease and the market center, 
which applies regardless of whether NYMEX prices or ANS spot prices are 
used. Section 206.112(b) then shows how differentials should be 
calculated between the market center and Cushing when the NYMEX price 
is used as the basis of value.

[[Page 24964]]

    The basic concepts of the proposed rule have been retained in the 
final rule. A lessee must use its arm's-length exchange agreements, if 
it has any, to determine the adjustment between the lease and market 
center or for any intermediate segments between those points. It may 
continue to use its actual transportation costs for any portion of the 
distance between the lease and market center over which oil is actually 
transported and not exchanged. If the lessee has an exchange agreement 
that is not at arm's length, the lessee must obtain MMS approval for 
using it as a location and quality adjustment. Until MMS approves a 
proposed location and quality differential, the lessee may use the 
location and quality differential in its non-arm's-length exchange 
agreement. If MMS prescribes a different differential, the lessee will 
need to adjust previously reported and paid royalties, together with 
appropriate interest payments or credits, based on the approved 
differential. To prevent ``double dipping,'' the lessee may not take 
both a transportation allowance and apply a location and quality 
differential between the same two points.
    In the final rule, in Sec.  206.112(a)(3), MMS has decided to 
retain the provision that requires a lessee to use its arm's-length 
exchange agreements that cover at least 20 percent of its production 
from the lease during the production month for the portion of oil from 
that lease for which the lessee does not have exchange agreements 
between the lease and the market center (or between some intermediate 
points). MMS believes that 20 percent is appropriate because it is 
greater than the royalty percentage under a typical onshore lease 
(12\1/2\ percent) or offshore lease (16\2/3\ percent).
    Section 206.112(a)(4) of the final rule addresses the situation 
where a lessee does not transport or exchange at least 20 percent of 
its oil produced from the lease to a market center. In that instance, 
you would use paragraphs (a)(1) and (a)(2) to value the less than 20 
percent portion (if any) that you transport or exchange (or transport 
and exchange) to a market center. For the remainder of your lease 
production, you must submit a proposal to MMS for a location and 
quality differential between the lease and the market center. You may 
use your proposed differential until MMS disapproves it. If MMS 
approves a different differential, you will need to adjust the 
previously reported and paid royalties, together with an interest 
payment or credit.
    Paragraph (c) addresses situations in which an additional quality 
differential is appropriate. For instance, MMS understands from our 
royalty-in-kind program that the All America Pipeline uses a sulfur 
adjustment of 50 cents per full percent, after the first percent 
difference in sulfur. MMS believes that the typical sulfur content of 
oil produced from Federal leases is in the 1 to 3 percent range. 
Therefore, MMS will change its proposed use of a 2.5 cent per 0.1 
percent adjustment to 5.0 cents per 0.1 percent sulfur unless MMS 
approves a higher adjustment. This adjustment would be similar to the 
factor used by the All America Pipeline and is consistent with the 
comments received from industry on common industry practice.
    Our intent in rewriting Sec.  206.112 was to clarify and simplify 
the existing rules. Certain technical issues were identified and 
evaluated to improve the effectiveness and efficiency of the rules by 
reducing litigation, assuring more contemporaneous compliance, reducing 
administrative cost to the Federal Government and lessees, and making 
Federal lands more attractive for development and leasing.

C. Transportation Cost Issues--Sec. Sec.  206.110 and 206.111

1. Proposed Change to Rate of Return on Undepreciated Capital 
Investment--Sec.  206.111(i)(2)
    MMS proposed an amendment to the regulations governing calculation 
of actual transportation costs in non-arm's-length situations by 
changing the allowed rate of return on undepreciated capital investment 
from 1.0 times the Standard & Poor's BBB bond rate to 1.5 times the 
Standard & Poor's BBB bond rate.
    Summary of Comments: Two States commented specifically that 1.5 
times the Standard & Poor's BBB bond rate is too high and does not 
reflect actual cost of capital. One State was particularly concerned 
that increasing the rate of return deduction would negatively impact 
State royalty income. It also believes the rate is not consistent with 
either MMS's former practice of rejecting the equity component of 
capital costs in determining a proper rate of return or with findings 
of the Energy Information Administration (EIA) that the rates of return 
are lower in the pipeline segment than in the exploration and 
production segment of the oil and gas industry. Specifically, the EIA 
found that the pipeline line of business averaged a return on 
investment approximately 50 percent of the return in the exploration 
line of business, and approximately 60 percent of the return in the oil 
and gas industry as a whole. This return was also slightly less than 
the Standard & Poor's BBB bond rate. Another State suggested a possible 
alternative to the proposal by applying the 1.5 times the Standard & 
Poor's BBB bond rate to pipelines constructed after the passage of the 
new regulations and retaining the 1.0 times Standard & Poor's BBB bond 
rate for existing infrastructure. Congressional commenters were 
concerned that the rate would negatively affect revenues.
    Industry commenters asserted that 1.5 times the Standard & Poor's 
BBB bond rate was not sufficient. 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 
cost of rate of return allowable should be between 1.6 and 1.8 times 
the Standard & Poor's BBB bond rate. Industry further suggests that 
non-pipeline-based transportation should be dealt with on a case-by-
case basis.
    MMS Response: MMS has examined some rates of return in the oil 
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 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.
    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. MMS, 
through its Offshore Minerals Management, Economics Division, has 
studied several years' worth of data for both non-integrated oil 
transportation companies and larger oil producers, both integrated and 
independent, that MMS believes are more likely to invest in oil 
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 
adjusted to 1.3 times the Standard & Poor's BBB bond rate. This number 
is

[[Page 24965]]

the mid-point of the range suggested by the MMS study, which concluded 
that the range of rates of return appropriate for oil pipelines would 
be in the range of 1.1 to 1.5 times the Standard & Poor's BBB bond 
rate. 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 oil 
that has already been discovered is much less and of a different 
nature. Both the MMS study and the data from 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.
    MMS believes that the study conducted by its Offshore Minerals 
Management Economics Division used the most relevant data for a 
reasonable period and is therefore the best source to decide on the 
appropriate rate of return. The fact that it also fell between the 
study cited by industry and the data cited by the State reaffirms our 
belief in its reasonableness.
2. Specific Transportation Cost Issues--Sec. Sec.  206.110 and 206.111
(i) Arm's-Length Transportation
    In Sec.  206.110, MMS proposed to add new paragraphs (b) and (c) 
that would specify many of the costs incurred for transporting oil 
under an arm's-length contract that are allowable deductions and those 
that are not deductible, respectively. MMS believes some costs are 
directly related to the movement of crude oil to markets away from the 
lease. MMS proposed that the rule include specific costs of 
transportation that are allowable.
    MMS also proposed to include specific costs as not being costs of 
transportation, either because they were costs of placing oil in 
marketable condition or costs of marketing, or otherwise simply not 
costs of transportation. They were proposed to be non-allowable as 
deductions from royalty value.
(ii) Non-Arm's-Length Transportation
    In Sec.  206.111, MMS proposed to add new paragraphs (b)(6) and 
(b)(7) that would specify many of the costs incurred for transporting 
oil under a non-arm's-length contract that are allowable deductions, 
but only to the extent they have not already been included in the 
actual cost calculation under paragraphs (d) through (j) of this 
section. MMS believes these costs are directly related to the movement 
of crude oil to markets away from the lease. MMS proposed that the rule 
include specific costs of transportation that are allowable.
    MMS also proposed specific costs as not being costs of 
transportation, either because they were costs of placing oil in 
marketable condition or costs of marketing, or otherwise simply not 
costs of transportation. They were proposed to be non-allowable as 
deductions from royalty value.
(iii) Technical Correction to Sec.  206.111(h)(5) Regarding 
Redepreciation
    We proposed to modify existing Sec.  206.111(h)(5) to delete the 
words ``who owned the system on June 1, 2000'' and replace them with 
the words ``from whom you bought the system'' to remedy an unintended 
consequence regarding depreciation when calculating a transportation 
allowance not involving an arm's-length transportation contract. The 
language in the June 2000 Rule would allow and require a second 
purchaser to go back to the depreciation schedule of the original 
owner, rather than continuing the depreciation of the first purchaser. 
This could result in either a higher or lower depreciable basis than 
was intended.
    Summary of Comments: States were uniformly opposed to modification 
of the transportation allowances in the June 2000 Rule and most 
questioned whether MMS was proposing to designate marketing costs as 
transportation. One State suggested that MMS is acting contrary to its 
long-held policy, which does not allow the deduction of direct or 
indirect marketing costs. The State further suggests that expanding the 
cost deductions will not serve to streamline the audit process because 
it believes that the expanded transportation costs will inevitably lead 
to litigation. Another State commented that MMS has proposed allowing 
some costs which it traditionally has not allowed as transportation. 
The commenter requested that MMS insert a provision stating that 
reimbursements for any or all of these cost elements received by the 
lessee, its affiliate, or its marketing agent, be included either in 
gross receipts or included as offsets to the expenses incurred in 
calculating transportation allowances. No State pointed to a single 
specific cost listed as allowable in the proposed rule that MMS has 
ever considered to be marketing or non-transportation related.
    Industry strongly supported the inclusion of specific 
transportation costs in the rule as a powerful tool for averting 
disputes arising out of lack of clarification of issues, but suggested 
that gauging and scheduling fees be included as deductible 
transportation costs.
    MMS Response: MMS intends to clarify and simplify the existing rule 
to reduce litigation, assure more contemporaneous compliance, reduce 
administrative costs to the Federal Government and lessees, and make 
Federal lands more attractive for development and leasing. MMS does not 
believe it can eliminate all disputes, but clarity within the 
regulatory structure affords the benefits listed above. After 
clarifying the costs that would be considered to be gas transportation 
costs and those that would be considered not to be transportation costs 
in the amendments to the gas valuation regulations promulgated in 1997, 
one lawsuit resolved whether the lines that MMS had drawn were 
reasonable. That case, Independent Petroleum Ass'n of America v. 
DeWitt, 279 F.3d 1036, cert. denied, 537 U.S. 1105 (2003) upheld all of 
MMS's determinations, except one involving unused firm capacity 
charges. Regarding unused firm capacity charges, the court held that 
MMS had not sufficiently explained why they were not related to 
transportation. MMS believes that by more fully explaining the 
distinctions, its policy is more likely to be upheld.
    In this rule, MMS does not modify its long-standing policy of not 
allowing as a deduction from gross proceeds the costs of placing 
production in marketable condition or costs of marketing production, 
including indirect or internal costs, or any other costs that are not 
necessary for the lessee to incur in order to move its oil. MMS 
believes that the costs it lists as transportation costs in the final 
rule are consistent with the reasoning that it has always followed in 
determining whether costs are for transportation or for something else.
    In Sec.  206.110(b), MMS identifies specific costs as allowable. 
You may not use any cost as a deduction that duplicates all or part of 
any other cost that you use under Sec.  206.110(b). The costs are:
    (1) The amount that you or your affiliate pay under an arm s-length 
transportation contract or tariff. This is the base price paid to 
transport oil at arm's length. It has always been allowable as a 
transportation expense.
    (2) Fees paid (either in volume or in value) for actual or 
theoretical line losses. Pipeline losses are actual or theoretical 
reductions in the volume of oil that travels through a pipeline. 
Pipeline losses are the result of either real, physical losses, or 
errors in the measurement of the oil. The lessee or its

[[Page 24966]]

affiliate may incur the cost of a pipeline loss either by a reduction 
in the volume of oil, resulting in lower gross proceeds received, or by 
a reduction in the value of oil on which the lessee received payment. 
Again, this is specifically allowable under existing regulations 
because these fees must be paid to a pipeline owner if they are part of 
the fee structure.
    (3) Fees paid for administration of a quality bank. Quality banks 
are the means by which the various shippers compensate each other if 
their oil is of higher or lower quality than the standard for the 
pipeline. Those shippers with higher quality oil receive a payment from 
the quality bank and those with lower quality oil must pay into the 
bank. Those payments are not usually taken into account to determine 
the value of the oil for Federal royalty purposes due to the provisions 
of Sec.  206.119. The fees allowed in this paragraph are fees paid to 
the person who administers the quality bank, not the payments made or 
received in adjusting the qualities of the injected oils. These banks 
are usually administered by pipeline owners, but may be administered by 
third parties. MMS is changing the final rule language by eliminating 
the phrase ``to a pipeline owner'' to acknowledge the fact that 
sometimes these fees may be paid to other persons who administer the 
quality bank. These fees are allowable because they are costs that are 
required to be incurred in order to ship oil through the pipeline to 
which they apply, and are not costs of placing the oil in marketable 
condition.
    (4) The cost of carrying on your books as inventory a volume of oil 
that the pipeline operator requires you to maintain, and that you do 
maintain, in the line as line fill. Some oil pipelines require that 
shippers leave oil in the pipeline so that the pipeline is full. Oil 
will not flow through the pipeline unless it is filled. The oil that 
the shipper (lessee) owns in the pipeline is, in effect, inventory that 
cannot ever be sold as long as the shipper uses the pipeline to 
transport its oil. If a shipper is required to maintain inventory, it 
loses the time value of money on the value of that oil for every month 
it is maintained in the line. For lines that do not require the 
shippers to maintain line fill, the pipeline owner will own the oil 
that fills the line and will charge the shipper as part of the arm's-
length price or tariff a cost at least equal to its capitalized costs. 
In order to treat lessees who ship through pipelines that require 
shippers to maintain line fill the same as lessees who ship through 
pipelines in which the owner provides line fill, MMS is allowing a 
deduction equal to the capitalized costs of the line fill--the monthly 
value of the oil that the shipper owns that serves as line fill times 
the rate of return.
    (5) Fees paid to a terminal operator for loading and unloading of 
crude oil into or from a vessel, vehicle, pipeline, or other 
conveyance.
    (6) Fees paid for short-term storage (30 days or less) incidental 
to transportation as required by a transporter.
    (7) Fees paid to pump oil to another carrier's system or vehicles 
as required under a tariff.
    (8) Transfer fees paid to a hub operator associated with physical 
movement of crude oil through the hub when you do not sell the oil at 
the hub. These fees do not include title transfer fees. Allowable costs 
(5) through (8) are all fees paid, as part of the cost of moving oil, 
to various persons who perform intermediate services associated with 
physical movement of oil. Specifically, the final rule allows fees paid 
to terminal operators for loading or unloading oil, fees paid for 
short-term storage incidental to transportation, fees paid to pump oil 
from one system or vehicle to another, and fees paid to physically move 
oil through a hub because they are costs incurred to move oil. Even 
short-term storage, if it is required by the transporter and not 
incurred for marketing purposes, is a cost associated with the movement 
of oil. MMS does not intend to allow any costs associated with 
marketing to be deducted. Therefore, the regulation limits storage 
costs to those required by transporters and limits transfer fees to 
those needed to physically move the oil, but disallows fees that merely 
transfer title--which is clearly a cost of marketing.
    (9) Payments for a volumetric deduction to cover shrinkage when 
high-gravity petroleum (generally in excess of 51 degrees API) is mixed 
with lower-gravity crude oil for transportation. These payments account 
for the fact that when high-gravity oil is mixed with lower-gravity 
oil, the volume of oil in the pipeline shrinks. If the charge is levied 
because your oil is of a significantly different quality than the other 
oil in the system, it is allowable as a transportation deduction 
because it affects the overall ability of the pipeline to transport 
oil. You may not deduct charges to adjust the quality of the oil to 
meet pipeline standards because that would be a cost of placing the oil 
in marketable condition.
    (10) Costs of securing a letter of credit, or other surety, that 
the pipeline requires you as a shipper to maintain. MMS believes that 
this is a cost that the lessee or its affiliate must incur to obtain 
the pipeline's transportation service, and therefore is a cost of 
moving the oil. It is not incurred for marketing purposes or to put the 
oil in marketable condition, but is paid solely to procure 
transportation services. Again, MMS will allow only the capitalized 
costs, when that is all that is appropriate, or a one-time expense, if 
that is appropriate. These costs should only include the currently 
allocable costs applicable to the Federal lease. MMS believes that 
shippers generally use two different means of assuring 
creditworthiness. The first involves a deposit or advanced payment in 
which the shipper incurs only the costs associated with the time value 
of money because it receives its deposit back. The other involves 
actual out-of-pocket costs to obtain a letter of credit, guarantee, or 
surety bond. MMS believes that these two means should be accounted for 
differently in calculating your transportation allowance.
    For example, in the first case, if you make a cash deposit of 2 
months of the expected transportation charges (say $50,000), and 
transport 100,000 barrels per month, of which 75,000 barrels are from a 
Federal lease, you must calculate the cost as follows:
    Multiply the deposit by the monthly rate of return, calculated by 
dividing the rate of return specified in Sec.  206.111(i)(2) by 12, and 
multiply that result by the proportion of total production from each 
Federal lease. In this example, if the Standard & Poor's BBB bond rate 
was 8 percent, the allowable monthly rate would be
[GRAPHIC] [TIFF OMITTED] TR05MY04.012

and that would be multiplied by the amount of the deposit to get the 
monthly cost, which would be $450. Then you could include the share of 
that applicable to the Federal lease (75,000/100,000) = \3/4\. So you 
could include $337 as an allowable transportation cost for as long as 
the $50,000 is on deposit (and the other factors remain unchanged).
    In the second case involving the expense of a letter of credit or 
other surety, if you pay your bank $5000 as a non-refundable fee for a 
letter of credit, you can include the proportion allocable to Federal 
production in the month that fee is paid, and then never again.
    MMS does not allow deduction of costs that are not actual costs of 
transporting oil. A new Sec.  206.110(c) lists the costs that MMS 
believes are clearly

[[Page 24967]]

not related to the transportation of oil. These are:
    (1) Fees paid for long-term storage (more than 30 days). Fees paid 
for long-term storage are due to a marketing choice and are not a 
necessary transportation cost.
    (2) Administrative, handling, and accounting fees associated with 
terminalling. Similarly, administrative fees associated with 
terminalling are not allowable because MMS believes that they are 
associated with administrative costs that are the lessee's obligation.
    (3) Title and terminal transfer fees.
    (4) Fees paid to track and match receipts and deliveries at a 
market center or to avoid paying title transfer fees. Non-allowable 
costs for title and terminal transfer fees and fees paid to avoid title 
and terminal transfer fees are associated with changes in ownership 
rather than movement and therefore are not costs of transportation.
    (5) Fees paid to brokers. Fees paid to brokers are treated 
similarly to items (3) and (4) above, because they are also costs 
associated with changes in ownership.
    (6) Fees paid to a scheduling service provider.
    (7) 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. 
Non-allowable costs (6) and (7) relate to scheduling, nominating, and 
accounting for sale and movement are internal costs that the lessee is 
required to provide at no cost to the lessor.
    (8) Gauging fees. Gauging fees are simply costs of measuring the 
volume of oil, which have traditionally been the responsibility of the 
lessee.
    Section 206.111 specifies how to calculate non-arm's-length 
transportation allowances. In Sec.  206.111(b)(6), MMS proposed certain 
costs as allowable costs of transportation as follows:
    (i) Volumetric adjustments for actual (not theoretical) line 
losses.
    (ii) The cost of carrying on your books as inventory a volume of 
oil that the pipeline operator requires you to maintain, and that you 
do maintain, in the line as line fill.
    (iii) Fees paid to a non-affiliated terminal operator for loading 
and unloading of crude oil into or from a vessel, vehicle, pipeline, or 
other conveyance.
    (iv) Transfer fees paid to a hub operator associated with physical 
movement of crude oil through the hub when you do not sell the oil at 
the hub. These fees do not include title transfer fees.
    (v) A volumetric deduction to cover shrinkage when high-gravity 
petroleum (generally in excess of 51 degrees API) is mixed with lower-
gravity crude oil for transportation.
    Several of these costs are the same as the costs allowed under 
Sec.  206.110(b) for arm's-length transportation described above. For 
example, MMS will allow lessees who transport through a non-arm's-
length arrangement to deduct the cost of carrying line fill on their 
books and will allow fees paid to non-affiliated terminal operators and 
hub operators associated with physical movement of oil. MMS is also 
adding a new cost parallel to these costs. If a lessee pays a non-
affiliated quality bank administrator, those costs are comparable to 
those incurred by arm's-length shippers.
    MMS will also allow certain costs similar to the costs allowed for 
arm's-length shippers. For example, MMS will allow volumetric losses, 
instead of fees, that cover shrinkage when high-gravity petroleum is 
mixed with low-gravity oil. Similarly, actual volumetric changes in 
line volume, whether they are losses or gains are allowable (or 
required to be added) for non-arm's-length shippers, in lieu of 
allowing fees for actual or theoretical line losses for arm's-length 
shippers.
    The costs identified as not being allowable for arm's-length 
shippers in Sec.  206.110(c) are also not allowed as transportation 
costs for shippers that transport their oil through non-arm's-length 
arrangements. In addition, MMS has specified that theoretical line 
losses are not allowable, because they are not actual costs to shippers 
who ship through non-arm's-length arrangements. The following have been 
designated as non-allowable transportation costs under Sec.  
206.111(b)(7):
    (i) Fees paid for long-term storage (more than 30 days).
    (ii) Administrative, handling, and accounting fees associated with 
terminalling.
    (iii) Title and terminal transfer fees.
    (iv) Fees paid to track and match receipts and deliveries at a 
market center or to avoid paying title transfer fees.
    (v) Fees paid to brokers.
    (vi) Fees paid to a scheduling service provider.
    (vii) 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.
    (viii) Theoretical line losses; and
    (ix) Gauging fees.
    The final rule retains the lists of allowable and unallowable costs 
in Sec. Sec.  206.110 and 206.111 because MMS believes they properly 
draw the line between those expenses that are needed for the movement 
of oil and those expenses that are incurred for some other purpose.
    The final rule adopts the proposed rule's changes to Sec.  
206.111(h)(5) related to redepreciation as proposed. When we amended 
the rules in March 2000, we intended the revisions regarding 
depreciation in the current rule to permit, one time only, a new 
depreciation schedule based on your purchase price when you purchase a 
transportation system from a previous owner. If a transportation system 
were sold more than once, subsequent purchasers would have to maintain 
the then-existing depreciation schedule.
    However, existing paragraph (h)(5) says ``if you or your affiliate 
purchase a transportation system at arm's length after June 1, 2000, 
from anyone other than the original owner, you must assume the 
depreciation schedule of the person who owned the system on June 1, 
2000.'' But if A were the original owner and still owned the system on 
June 1, 2000, and subsequently sold the system to B after June 1, 2000, 
who in turn sold it to C, the rule as written says that C would have to 
assume original owner A's depreciation schedule. This was not MMS s 
intent. To be consistent with the intended result, C should assume B's 
depreciation schedule in this situation.
    Therefore, to reflect the original intent, MMS is modifying Sec.  
206.111(h)(5) to delete the words ``who owned the system on June 1, 
2000'' and replace them with the words ``from whom you bought the 
system.'' This change will enable C in the example above to assume the 
depreciation schedule of B based on B's purchase price of the 
transportation system and subsequent reinvestment.

D. Treatment of Joint Operating Agreements--Sec. Sec.  206.102 and 
210.53

    MMS proposed to remove the presumption that sales to a co-lessee 
under a joint operating agreement (JOA) are not at arm's length. The 
proposal required changing the reporting instructions in 30 CFR Sec.  
210.53 with respect to sales under JOA to facilitate review and audit 
of these transactions.
    Summary of Comments: A State respondent opposed the treatment of 
JOAs as arm's-length transactions. The State declared that MMS's 
treatment in the 2000 preamble was consistent with the practical 
realities of the ``proceeds'' received by co-lessees under JOAs. Co-

[[Page 24968]]

lessees are working interest owners. As such, they share in costs that 
royalty owners do not incur. The nature of the very lease interests 
between a royalty owner and a working interest owner differ. Co-
lessees, in essence, are given a ``deduction'' benefit, which they 
would not receive if their royalty were calculated under the non-arm's-
length rules.
    The respondent from industry agreed with the proposed changes, but 
requested that the language under Sec.  210.53(1)(c) be amended from 
``each working interest owner'' to ``the working interest owners.'' The 
change in wording would provide for a second reporting line but not 
more, easing reporting burdens.
    MMS Response: MMS does not believe there should be a presumption 
that transactions under JOAs are sales or not sales. Neither does MMS 
believe that there should be a presumption that transactions under JOAs 
are at arm's length or are not at arm's length. When a party to a JOA, 
who is not the operator, allows the operator to dispose of the non-
operator's share of oil production in exchange for the consideration 
provided under that agreement, MMS recognizes that some of these 
arrangements may be sales of the production. Holding that a disposition 
under a JOA is not a sale, while a disposition under a sales contract, 
with identical terms, is treated as a sale, would be a case of form 
over function. MMS believes that it is the substance of the 
transaction, rather than the form, that determines whether a 
transaction is treated as arm's length or not.
    MMS believes that, when a contract of whatever form results in the 
Federal royalty owner sharing in costs that are not properly sharable, 
the definition of gross proceeds together with the exceptions in Sec.  
206.102(c)(2) provide sufficient tools for MMS to assure that the 
lessor will not share in costs that are not properly shareable. If the 
operator is providing marketing services to its co-lessees, the MMS may 
require that they be provided at no cost to the lessor, regardless of 
whether the oil is disposed through the JOA or through a sales 
contract.
    MMS's current practice is to include detailed reporting guidance in 
the ``Minerals Revenue Reporter Handbook''. MMS decided that specific 
reporting guidance for JOA's should not be included in our regulations. 
MMS agrees with industry that having the designee report a separate 
line for each working interest owner on the Form MMS-2014, Report of 
Sales and Royalty Remittance, is not needed. Therefore, MMS is not 
modifying Sec.  210.53 as proposed but will modify the Minerals Revenue 
Reporter Handbook to require a designee to report, on the Form MMS-
2014, one line for the share of the production the designee purchased 
from the working interest owners at arm's length and report on separate 
lines the required information for the remaining shares of the 
production valued (1) as an arm's-length sale by you or your affiliate 
under Sec.  206.102; or (2) at an index price under Sec.  206.103.

E. Limit on Grace Period for Reporting Changes--Sec.  206.121

    MMS proposed a technical correction to the regulation at Sec.  
206.121 that permitted a grace period for reporting and paying 
royalties after the June 2000 Rule became effective to give royalty 
payors adequate time to change their systems. We proposed to end-date 
the grace period for such adjustments, because we consider 3 years to 
be sufficient time to have reported and paid royalties under the 
regulations published in 2000.
    Summary of Comments: One State commented that, if MMS decides to 
add a new grace period in the final rule, it should retain the system 
change requirement associated with the rule. Industry comments 
supported the elimination of the grace period associated with the June 
2000 Rule, and recommended the implementation of a new grace period for 
the final rule primarily to account for system changes associated with 
the potential re-definition of JOAs.
    MMS Response: MMS agrees that the grace period from the June 2000 
Rule should be discontinued. We consider 3 years to be sufficient time 
to have reported and paid royalties under the June 2000 Rule. Further, 
since we received no requests for relief after the June 2000 Rule was 
published, MMS does not believe that implementation of a new grace 
period is necessary. This is especially true given the fact that we 
have modified the treatment of working interest owners under JOAs in 
the final rule to alleviate reporting of each interest owner's 
production. Therefore, Sec.  206.121 is removed from the final rule.

F. Other Technical Changes

    In addition, MMS proposed making a technical change to the 
definition of ``affiliate'' in Sec.  206.101. MMS proposed changing 
paragraph (2) of the definition of ``affiliate'' by striking the words 
``of between 10 and 50 percent'' and substituting therefore the words 
``10 through 50 percent'' because the current definition does not 
specify the treatment of a situation in which one person owns exactly 
50 percent of another person.
    Summary of Comments: Industry supported the redefinition of 
affiliate.
    MMS Response: Based on the comment received and the need for 
clarification, MMS is modifying the definition of ``affiliate'' in 
Sec.  206.101(2) as proposed.

II. Procedural Matters

1. Summary Cost and Royalty Impact Data

    Summary of Comments: MMS received comments questioning the 
following: (1) MMS assumptions used regarding the percentage of arm's-
length sales and the percentage of not-at-arm's-length sales in the 
analysis, and (2) MMS assumptions on allowances. One State and several 
congressional commenters questioned (3) why revenue impacts published 
in the proposed rule were ranges instead of single figures.
    MMS Response: On the question of assumptions of percentages of 
arm's-length sales and the percentage of not-at-arm's-length sales in 
the analysis, MMS provides the following information. At the time of 
the proposed rulemaking, MMS estimated the percentage of arm's-length 
sales and the percentage of not-at-arm's-length sales at 50 percent 
each. MMS did not use ``Sales Type Code'' data reported by companies on 
the Form MMS-2014, Report of Sales and Royalty Remittance. We have 
recently reviewed data reported using the ``Sales Type Code'' on the 
Form MMS-2014 from October 2002 to March 2003 and found that 70 percent 
of crude oil produced from Federal leases was reported as being sold at 
arm's length and 30 percent was reported as being not sold at arm's 
length. However, because the ``Sales Type Code'' is a new reporting 
requirement and because the reported data has not yet been audited, MMS 
believes that 50 percent is a better estimate of the actual amount of 
crude oil that is not sold at arm's-length.
    On the question of assumptions on allowances, MMS provides the 
following information. When MMS was researching the revenue impacts 
associated with the proposed rule, we considered three variables 
associated with the transportation-related changes to the existing 
regulations: (a) Whether allowances are at arm's length or not at arm's 
length, (b) the range of the cost components, and (c) the amount of 
production taken in kind.
    Regarding the first variable (a), since 1996, MMS has not collected 
forms which indicate if allowances are at arm's length or not at arm's 
length. In

[[Page 24969]]

preparing the proposed rule, certain assumptions were made concerning 
actual impacts to revenues.
    MMS assumed 50 percent of transportation allowance transactions 
were at arm's length and that 50 percent were not at arm's length. MMS 
does not collect data on whether allowances are at arm's length. MMS 
does collect data on whether sales are at arm's length, but there is no 
relationship between the type of sale and the type of allowance.
    Regarding the second variable (b), MMS also assumed that certain 
costs, such as the cost of a letter of credit, would range from $.02 to 
$.05 per barrel. Because of uncertainty associated with the exact 
amount of each deductible cost, MMS chose to publish a range of 
possible effects rather than an average. This explains why revenue 
impacts published in the proposed rule were ranges instead of single 
figures.
    Regarding the third variable (c), because production taken in kind 
is not subject to the transportation regulations in the proposed rule, 
oil taken in kind has the potential to significantly affect the total 
of transportation allowances reported. MMS applied high (77 percent) 
and low (19 percent) range factors for production taken in kind to 
account for scenarios at either extreme, to demonstrate the potential 
range of revenue impacts.
    Summarized below are the estimated costs and royalty impacts of 
this 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 accruing 
in the first year after implementation of this rule and those accruing 
on a continuing basis each year thereafter.
A. Industry
    (1) Expected Royalty Increase--NYMEX-based valuation applied to oil 
not sold at arm's length.
    Under this rule, industry will value oil based on a market price 
that more closely represents the true value of the oil. We believe this 
may result in industry paying additional royalties compared to the 
Federal oil valuation rule that became effective June 1, 2000. Provided 
below are estimates of any significant increased royalties.
    This rule maintains many of the provisions of the June 2000 Rule 
including the concept of separate valuation methodologies linked to 
different production locations. This analysis is divided into the two 
areas affected by these changes. They include the Rocky Mountain 
Region, and the ``Rest of the Country,'' including the Gulf of Mexico. 
Since we retained the use of ANS spot prices for California and Alaska, 
we removed the royalty impacts of using NYMEX pricing in California and 
Alaska from the analysis. This analysis highlights the impacts of 
modifying the pricing provisions and methodologies. The allowed 
adjustments for transportation and quality as outlined in the June 2000 
Rule also will change somewhat, and some additional corresponding 
analysis is included.

``Rest of the Country''

    In valuing production not sold under an arm's-length contract, the 
June 2000 Rule employed the spot market index price of the oil most 
closely associated with the production, with appropriate adjustments 
for location and quality. The timing of the spot market that 
corresponds with the production month was the quoted average from an 
MMS-approved publication from the 26th day of the month prior to the 
current production month to the 25th day of the current production 
month. For example, December royalty production was valued using the 
spot quotes for the oil most similar in location and quality from 
November 26th through December 25th.
    The new methodology for the ``Rest of the Country,'' as discussed 
earlier, is the NYMEX Calendar Month Average daily settlement price 
with the roll and a quality and location differential. This method uses 
a trading month quality and location differential (found in MMS-
approved publications and based on spot price quotes) applied to the 
average of the daily NYMEX prices, excluding weekends and holidays, 
during the production month for deliveries during the prompt month as 
defined in this rule. For example, for the month of December, assume a 
producer seeks to value production whose characteristics are closely 
related to Light Louisiana Sweet (LLS) crude oil. The grade 
differential established over the period October 26 through November 25 
will be applied to the average of the daily NYMEX prompt month prices 
published for each day in the month of December. The grade differential 
is the WTI spot price for the period October 26-November 25 less the 
LLS spot price for the same period. Assuming the WTI value is $29.00 
per barrel and the LLS value is $28.00 per barrel, the differential is 
$1.00 per barrel.
    The forward roll is added to the calendar month average NYMEX value 
and is determined by adding \2/3\ of the difference between the average 
daily NYMEX settlement prices for deliveries during the prompt month 
that is the same as the month of production and the average of those 
prices for deliveries during the next succeeding month plus \1/3\ of 
the difference between the average of the daily NYMEX settlement prices 
for deliveries during the prompt month that is the same as the month of 
production and the average of those prices for deliveries during the 
second month following the month of production as specifically defined 
in the rule. Assuming the roll calculation results in a value of +$.30 
per barrel, the calculated royalty value, assuming the NYMEX calendar 
month average price is $29.50 per barrel, is $28.80 per barrel 
(including both the roll and the differential). It is calculated as 
follows for all royalty production not disposed of at arm's length in 
the month of December:
(NYMEX Calendar Month Average + roll)--(Spot average WTI-Spot Average 
LLS)
($29.50 + $.30)-($29-$28) = $28.80 per barrel for December royalty 
production valued as not sold under an arm's-length contract.

    We compared prices under NYMEX adjusted for the roll and the grade 
differential discussed above with prices calculated under the June 2000 
Rule based on spot prices at each of the market centers applicable in 
the ``Rest of the Country''--e.g., Midland, Texas; St. James, 
Louisiana; and Empire, Louisiana. We found that over the period April 
2000 through December 2002, or the period from approximately when the 
June 2000 Rule became effective through the end of calendar year 2002, 
the adjusted average monthly NYMEX price with the roll (adjusted from 
Cushing to each of these market centers) exceeded the monthly average 
spot prices for these market centers by an average of $.31 per barrel. 
We also performed this comparison back to the beginning of 1999 and 
found that the difference is slightly higher over the entire period 
January 1999 through December 2002. We chose the $.31 per barrel 
increment as the basis for our royalty impact estimates.
    In estimating the impact of a change to NYMEX valuation, we made 
several assumptions in addition to the $.31 per barrel increment. We 
assumed that 50 percent of all Federal barrels would be valued under 
the non-arm's-length provisions, that the offshore royalty rate is one-
sixth and the onshore royalty rate is one-eighth, and that volumes 
taken in kind would vary from 50,000 barrels per day to 180,000 barrels 
per day.
    The 50,000 includes only barrels currently taken in the small 
refiner program, and the 180,000 includes

[[Page 24970]]

small refiner volumes plus barrels currently going to the Strategic 
Petroleum Reserve. We then subtracted the volumes taken in kind and 
applied the $.31 per barrel figure to the remaining barrels assumed to 
be valued under the non-arm's-length provisions. We estimate increased 
costs to industry in the form of higher royalty payments of $4,303,913 
to $11,658,663 per year.

Rocky Mountain Region

    Determining the impact of the final rule from the June 2000 Rule 
methodology for valuing oil not sold at arm's length in the Rocky 
Mountain Region is difficult. This is largely because there is no 
prescribed formula currently in place, but rather a series of benchmark 
procedures that lessees apply on an individual basis. The new 
methodology for the third benchmark is the NYMEX Calendar Month Average 
daily settlement price with appropriate differentials, but without the 
roll discussed above. This method uses a trading month differential 
(found in MMS-approved publications and based on spot price quotes) 
applied to the average of the daily NYMEX prices, excluding weekends 
and holidays, published for each day during the production month for 
deliveries during the prompt month as defined in this rule. This 
methodology will apply only if the lessee has no MMS-approved tendering 
program and elects to value production based on NYMEX prices rather 
than the volume-weighted average of gross proceeds received under 
arm's-length contracts. Where the third benchmark applies, valuation of 
Wyoming Sweet will rely on differentials between WTI at Cushing and the 
lease. For example, for the month of December, assume a producer seeks 
to value production for Wyoming Sweet crude oil. The grade differential 
established over the period October 26 through November 25 will be 
applied to the average of the daily NYMEX prompt month prices published 
for each day in the month of December. For December production, the 
average value of Wyoming Sweet against WTI determined October 26th 
through November 25th applied to the NYMEX calendar month average 
becomes the basis of value:

(Trading month WY Sweet spot oil assessment-Spot WTI assessment) + 
NYMEX calendar month average.

    We compared prices under NYMEX adjusted for the grade differential 
(without the roll) with prices calculated under the existing rule based 
on spot prices at Cushing. We used the same time period, April 2000 
through December 2002, as we did for the ``Rest of the Country.'' Over 
this period, the monthly average spot price exceeded the adjusted 
average monthly NYMEX price by about $.06 per barrel. We also performed 
this comparison back to the beginning of 1999 and found that the 
adjusted NYMEX price exceeded the monthly average spot price by about 
$.02 per barrel over the entire period January 1999 through December 
2002. To illustrate the highest potential cost to industry, we chose 
the $.02 per barrel increment of NYMEX over spot as the basis for our 
benefit and cost estimates.
    In estimating the impact of a change to NYMEX valuation, we made 
several assumptions in addition to the $.02 per barrel increment. 
First, we assumed that 50 percent of all Federal barrels would be 
valued under the non-arm's-length provisions. Then, because there are 
four non-arm's-length benchmarks in the Rocky Mountain Region and only 
the third benchmark will rely on NYMEX prices, we assumed that 25 
percent of all Federal barrels that are valued under the benchmarks 
will be valued under each of the benchmarks; therefore, only 25 percent 
of those barrels will rely on NYMEX prices. (None of the other three 
benchmarks will change.) Consequently, 12\1/2\ percent of all Federal 
barrels will be valued under the third non-arm's-length benchmark. We 
also assumed that the royalty rate is one-eighth, and that volumes 
taken in kind (these are from Wyoming only) would be about 4,000 
barrels per day. We then subtracted the volumes taken in kind and 
applied the $.02 per barrel figure to the remaining barrels assumed to 
be valued under the non-arm's-length provisions. We estimate higher 
royalty payments to be about $11,738 per year.
    (2) Expected Royalty Decrease--Increased Allowable Costs.
    (i) 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.
    MMS does not routinely collect detailed allowance information, such 
as affiliation between the payor and transporter or the cost components 
used to calculate a non-arm's-length allowance rate. Therefore, we had 
to make several broad assumptions in order to estimate the impact of 
this rule. We assumed that 50 percent of all 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\ depreciation expenses, and \1/3\ operation, 
maintenance and overhead expenses. During FY 2001, royalty payors 
reported transportation allowance deductions of $45,363,394 for Federal 
oil production. Based on our assumptions, if \1/3\ of the allowance 
deductions are non-arm's-length, then $22,681,697 of the total 
allowances fell in this category. If \1/3\ of the allowance is made up 
of the rate of return, this equals $7,560,565. Therefore, we estimate 
that increasing the basis for the rate of return by 30 percent could 
result in additional allowance deductions of $2,268,169 ($7,560,565 x 
.30). Our review of transportation allowances deducted from oil 
royalties in the States of Wyoming, Colorado, Utah, and New Mexico 
revealed minimal amounts reported for onshore leases. Therefore, we 
assumed that virtually this entire increase will impact offshore 
royalties only.
    (ii) Line Loss as a component of a non-arm's-length transportation 
allowance.
    For offshore production, the estimate is based on the total 
offshore oil royalties for FY 2001 of $2,069,450,791. We assumed that 
50 percent of all allowances are non-arm's-length, and that oil 
pipeline losses are 0.2 percent of the volume of the production. 
Therefore, before making the further adjustments discussed below, we 
estimated this change could result in additional transportation 
allowances of $2,069,451 per year ($2,069,450,791 x .50 x .002). For 
onshore production, we used total onshore oil royalties for FY 2001 of 
$252,575,890. We assumed that 50 percent of all allowances are non-
arm's-length, and that oil pipeline losses are 0.2 percent of the 
volume of the production. Therefore, before making the further 
adjustments discussed below, we estimated this change could result in 
additional transportation allowances of $252,576 per year ($252,575,890 
x .50 x .002).
    We also recognize that substantial volumes of offshore production 
are taken in kind and are not subject to the regulations regarding 
transportation. We estimated that between 50,000 barrels of oil per day 
(BOPD) and 180,000 BOPD may be taken in kind. The wide variance in this 
estimate is caused by the approximately 130,000 BOPD which may be taken 
in kind and placed into the Strategic Petroleum Reserve. Based on daily 
offshore Federal royalty share of 222,100 BOPD, the amount of oil 
transportation subject to these regulations could range from a high of 
77 percent of the royalty share of production to a low of 19 percent of 
the royalty share of production. [(222,100 - 50,000) / 222,100 = 77 
percent; (222,100 - 180,000) / 222,100 = 19 percent]. Applying the high 
and low range factors

[[Page 24971]]

for oil taken in kind, this could result in additional transportation 
allowance deductions for offshore leases ranging from $393,196 
($2,069,451 x 19 percent) to $1,593,477 ($2,069,451 x 77 percent) per 
year.
    (iii) Quality Bank Administration Fees as a component of an arm's-
length and a non-arm's-length transportation allowance.
    For offshore oil production, our estimate is based on the total 
offshore oil royalty volume for FY 2001 of 81,066,567 barrels. We also 
estimated that quality bank administrative fees were $.002 per barrel. 
We estimated that allowing such fees could result in additional 
offshore transportation allowances of $162,133 (81,066,567 x $.002) per 
year before considering the effects of oil taken in kind. Applying the 
high and low range factors for oil taken in kind, this could result in 
additional transportation allowance deductions ranging from $30,805 
($162,133 x 19 percent) to $124,842 ($162,133 x 77 percent) per year. 
For onshore production, we used the onshore royalty volume for FY 2001 
of 9,496,181 barrels. Allowing such fees could result in additional 
allowances of $18,992 (9,496,181 x $.002).
    (iv) Line Fill as a component of an arm's-length and a non-arm's-
length transportation allowance.
    For offshore oil production, our estimate is based on the total 
offshore oil royalty volume for FY 2001 of 81,066,567 barrels. We 
estimated that line fill costs ranged from $.02 to $.05 per barrel. We 
then estimated that this factor could result in additional 
transportation allowances of $1,621,331 (81,066,567 x $.02) to 
$4,053,328 (81,066,567 x $.05) before considering the effects of oil 
taken in kind. Applying the high and low range factors for oil taken in 
kind, this could result in additional offshore transportation allowance 
deductions ranging from $308,052 ($1,621,331 x 19 percent) to 
$3,121,062 ($4,053,328 x 77 percent) per year. For onshore production, 
we estimated that this factor could result in additional transportation 
allowances of $189,924 (9,496,181 x $.02) to $474,809 (9,496,181 x 
$.05).
    (v) The cost of a Letter of Credit as a component of an arm's-
length transportation allowance.
    Again, we assumed that 50 percent of allowances are at arm's 
length. We again based the estimate on the total offshore oil royalty 
volume for FY 2001 of 81,066,567 barrels. We estimated that letter of 
credit costs ranged from $.02 to $.05 per barrel. We thus estimated 
that this could result in additional transportation allowances of 
$810,666 (81,066,567 x $.02 x .5) to $2,026,664 (81,066,567 x $.05 x 
.5). Applying the high and low range factors for oil taken in kind, 
this could result in additional offshore transportation allowance 
deductions ranging from $154,027 ($810,666 x 19 percent) to $1,560,531 
($2,026,664 x 77 percent) per year. For onshore production, we 
estimated that this factor could result in additional transportation 
allowances of $94,962 (9,496,181 x $.02 x .5) to $237,405 (9,496,181 x 
$.05 x .5).
    (vi) Royalty Reduction Summary, items (i)-(v)--Additional 
Deductions for Allowances.
    We estimate that between $3,154,249 and $8,668,081 in additional 
transportation allowances could be deducted in determining Outer 
Continental Shelf lease royalties based on an increased rate of return 
and permissibility of line losses for non-arm's-length allowances; 
permissibility of quality bank administration fees and line fill costs 
for both arm's-length and non-arm's-length allowances; and 
permissibility of letter of credit costs for arm's-length allowances. 
Also, for these same items, we estimate that between $556,454 and 
$983,782 of additional transportation allowances may be deducted in 
determining onshore Federal lease royalties.
    (3) Net Expected Change in Royalty Payments from Industry.
    We estimate a net expected change in royalty payments from industry 
of $1,311,743. That amount is calculated by the sum of the Royalty 
Increase for the Rocky Mountain Region ($11,738) plus the mid point 
value of the ``Rest of the Country'' ($7,981,288) plus the mid point 
value of the Royalty Decrease for Increased Allowable Costs (-
$6,681,283).
    (4) Expected Range of Royalty Impact on Industry.
    We estimate the expected range of the royalty impact on industry is 
-$5,336,212 to $7,959,698. The low end of that range is the sum of the 
Royalty Increase for the Rocky Mountain Region ($11,738) plus the 
lowest impact for the ``Rest of the Country'' ($4,303,913) plus the 
highest impact of the Royalty Decrease for Increased Allowable Costs (-
$9,651,863). The high end of that range is the sum of the Royalty 
Increase for the Rocky Mountain Region ($11,738) plus the highest 
impact for the ``Rest of the Country'' ($11,658,663) plus the lowest 
impact of the Royalty Decrease for Increased Allowable Costs (-
$3,710,703). For example, $11,738 + $4,303,913 -$9,651,863 = -
$5,336,212 is the low range impact for Industry.
    (5) Cost--Administrative.
    (i) System Modifications to reflect NYMEX pricing basis.
    We believe that any increases in administrative costs related to 
the changes in non-arm's-length valuation procedures will be minimal. 
These procedures involve NYMEX prices, which are readily available at 
no cost from numerous sources. They also involve determination of spot 
price differentials at various locations. We believe that anyone who 
used the non-arm's-length provisions of the June 2000 Rule already has 
access to the needed publications and exchange agreements. For some 
lessees, modification of computer programs related to royalty 
calculation and payment may be needed. We think that only about 50 of 
the approximately 800 Federal oil royalty payors will use the non-
arm's-length provisions and thus might need to do some reprogramming. 
Using an estimated cost of $5,000 for each such payor to do its 
reprogramming, the added one-time cost will be $250,000.
    (ii) Location Differential under Sec.  206.112(c)(1).
    We anticipate that, in a very few cases, companies may request 
approval of proposed differentials when less than 20 percent of the 
crude oil is transported or exchanged from the lease. These requests 
must: (1) Be in writing; (2) identify specifically all leases involved, 
the record title or operating rights owners of those leases, and the 
designees for those leases; (3) completely explain all relevant facts, 
including informing MMS of any changes to relevant facts that occur 
before MMS responds to a request; (4) include copies of all relevant 
documents; (5) provide the company's analysis of the issue(s), 
including citations to all relevant precedents (including adverse 
precedents); and (6) suggest the proposed differential. We estimate 
that there will be two such requests annually. We estimate the annual 
burden for these requests will be 660 hours (2 x 330), including 
recordkeeping. Based on a per-hour cost of $50, we estimate the cost to 
industry is $33,000.
B. State and Local Governments
    This rule will not impose any additional burden on local 
governments. MMS estimates that States impacted by this rule may 
experience changes in royalty collections as indicated below:
    (1) Expected Royalty Increase--From Use of NYMEX Pricing.
    States receiving revenues from offshore OCS Section 8(g) leases 
will share in a portion of the estimated additional $4,303,913 to 
$11,658,663 in royalties that will accrue annually from

[[Page 24972]]

the ``Rest of the Country,'' under this valuation methodology. Based on 
each OCS Section 8(g) State's share of total offshore royalties for FY 
2001 and their OCS Section 8(g) disbursement percentage, we estimate 
the States' OCS Section 8(g) share to be between $26,363 and $71,119. 
Onshore States will receive additional revenue of $317,682.
    For the Rocky Mountain Region, we estimate an increase in the 
States' share of royalty revenues of about $5,869 per year.
    (2) Expected Royalty Decrease--Allowable Costs: Increased Rate of 
Return and Inclusions of Line Loss, Quality Bank Administration Fees, 
Line Fill and Letters of Credit as components of allowance costs.
    (3) Net Expected Change to Royalty Payments to States.
    We estimate that the net expected change to royalty payments to the 
States is -$55,553. That amount is calculated by the sum of the Royalty 
Increase for the Rocky Mountain Region ($5,869) plus the mid point 
value of the ``Rest of the Country'' ($366,423) plus the mid point 
value of the Royalty Decrease for Increased Allowable Costs (-$42,786 
for OCS 8(g) States and -$385,059 for all States).
    (4) Expected Range of Royalty Impact on States.
    We estimate the expected range of the royalty impact on States 
would be -$204,773 to $93,628. The low end of the range is the sum of 
the Royalty Increase for the Rocky Mountain Region ($5,869) plus the 
lowest impact for the ``Rest of the Country'' ($344,045) plus the 
highest impact of the Royalty Decrease for Increased Allowable Costs (-
$62,756 and -$491,891). The high end of the range is the sum of the 
Royalty Increase for the Rocky Mountain Region ($5,869) plus the 
highest impact for the ``Rest of the Country'' ($388,801) plus the 
lowest impact of the Royalty Decrease for Increased Allowable Costs (-
$22,815 and -$278,227).
C. Federal Government
    Because many of the changes in this rule are technical 
clarifications and others are relatively minor changes to the valuation 
mechanisms, the impacts to the Federal Government should be minimal, 
especially in administration.
    (1) Expected Royalty Increase--from use of NYMEX pricing.
    The Federal Government will receive an estimated $4,303,913 to 
$11,658,663 in royalties each year from the ``Rest of the Country,'' of 
which affected States will receive a portion. We estimate the Federal 
share of offshore royalties to be between $3,642,186 and $10,952,180 
and the Federal share of onshore royalties at $317,682. For the Rocky 
Mountain Region, we estimate an increase in royalty revenues of about 
$5,869 per year of the estimated additional $11,738 in royalties 
accruing to production in the affected States.
    (2) Expected Royalty Decrease--Allowable Costs: Increased Rate of 
Return and Inclusions of Line Loss, Quality Bank Administration Fees, 
Line Fill and Letters of Credit as components of allowance costs.
    We estimate that between $3,710,703 and $9,651,863 per year in 
additional transportation allowances may be deducted in calculating 
Federal royalties. Of that, between $22,815 and $62,756 is attributed 
to OCS 8(g) States and between $278,227 and $491,891 per year is 
attributed to all other States.
    (3) Net Expected Change in Royalty Payments to the Federal 
Government.
    We estimate a net expected change in royalty payments to the 
Federal Government of $1,367,296. That amount is calculated by the sum 
of the Royalty Increase for the Rocky Mountain Region ($5,869) plus the 
mid point value of the ``Rest of the Country'' ($7,614,865) plus the 
mid point value of the Royalty Decrease for Increased Allowable Costs 
(-$6,253,438).
    (4) Expected Range of Royalty Impact on the Federal Government.
    We estimate the expected range of the royalty impact on the Federal 
Government is -$5,131,479 to $7,866,070. The low end of that range is 
the sum of the Royalty Increase for the Rocky Mountain Region ($5,869) 
plus the lowest impact for the ``Rest of the Country'' ($3,959,868) 
plus the highest impact of the Royalty Decrease for Increased Allowable 
Costs (-$9,097,216). The high end of that range is the sum of the 
Royalty Increase for the Rocky Mountain Region ($5,869) plus the 
highest impact for the ``Rest of the Country'' ($11,269,862) plus the 
lowest impact of the Royalty Decrease for Increased Allowable Costs (-
$3,409,661).
    (5) Cost--Location Differential under Sec.  206.112(c).
    We anticipate that companies may request approval of proposed 
differentials when they transport or exchange less than 20 percent of 
the crude oil from the lease. In processing these requests, MMS must: 
(1) Respond in writing; (2) verify for all leases involved, the record 
title or operating rights owners of those leases, and the designees for 
those leases; (3) completely explain all relevant facts; (4) obtain 
copies of all relevant documents; (5) analyze the issue(s), including 
citations to all relevant precedents (including adverse precedents); 
and (6) potentially defend our determination. For the above written 
requests, we estimate that there will be two responses annually. We 
estimate that the annual burden for these requests is 660 hours (2 x 
330), including recordkeeping. Based on a per-hour cost of $50, we 
estimate the cost to the Federal Government is $33,000.
D. Summary of Royalty Impacts and Costs 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. 
For the purpose of calculation of the net expected change in royalty 
impact, we assumed that the average for royalty increases or decreases 
will be the midpoint of this range.

                  Summary of Costs and Royalty Impacts
------------------------------------------------------------------------
                                  Costs and royalty increases or royalty
                                                 decreases
           Description           ---------------------------------------
                                      First year       Subsequent years
------------------------------------------------------------------------
A. Industry:
    (1) Royalty Increase from     Rocky Mountain      Rocky Mountain
     use of NYMEX pricing.         Region: $11,738.    Region: $11,738.
                                  ``Rest of the       ``Rest of the
                                   Country'':          Country':
                                   $4,303,913 to       $4,303,913 to
                                   $11,658,663.        $11,658,663.
    (2) Royalty Decrease--        -$3,710,703 to -    -$3,710,703 to -
     Increased Allowable Costs.    $9,651,863.         $9,651,863.
    (3) Net Expected Change in    $1,311,743........  $1,311,743.
     Royalty Payments from
     industry \1\.
    (4) Expected Range of         -$5,336,212 to      -$5,336,212 to
     Royalty Impact \2\.           $7,959,698.         $7,959,698.

[[Page 24973]]

 
    (5) Administrative Cost--     $283,000..........  $33,000.
     Modification of Systems and
     Submittal of Location
     Differential Requests.
B. State and Local Governments:
    (1) Royalty Increase--        Rocky Mountain      Rocky Mountain
     Increased Royalty Revenue     Region: $5,869.     Region: $5,869.
     in Terms of the States'
     Share of Federal Royalties
     from use of NYMEX pricing.
                                  ``Rest of the       ``Rest of the
                                   Country'':          Country'':
                                   $344,045 to         $344,045 to
                                   $388,801.           $388,801.
    (2) Royalty Decrease--        OCS Sec.   8(g)     OCS Sec.   8(g)
     Increased Allowable Costs     States: -22,815     States: -22,815
     in Terms of the States'       to -62,756.         to -62,756.
     Share of Federal Royalties.
                                  All Other States: - All Other States:
                                   278,227 to -        278,227 to -
                                   491,891.            491,891.
    (3) Net Expected Change to    -55,553...........  -55,553.
     Royalty Payments to States
     \1\.
    (4) Expected Range of         -204,733 to 93,628  -204,733 to
     Royalty Impact \2\.                               93,628.
C. Federal Government:
    (1) Royalty Increase--        Rocky Mountain      Rocky Mountain
     Increased Royalty Revenues    Region: 5,869.      Region: 5,869.
     Net of the States' Share
     from use of NYMEX pricing.
                                  ``Rest of the       ``Rest of the
                                   Country'':          Country'':
                                   3,959,868 to        3,959,868 to
                                   11,269,862.         11,269,862.
    (2) Royalty Decrease--        -3,409,661 to -     -3,409,661 to -
     Increased Allowable Costs     9,097,216.          9,097,216.
     Net of the States' Share.
    (3) Net Expected Change in    1,367,296.........  1,367,296.
     Royalty Payments to the
     Federal Government \1\.
    (4) Expected Range of         -5,131,479 to       -5,131,479 to
     Royalty Impacts \2\.          7,866,070.          7,866,070.
    (5) Cost of Administering     33,000............  33,000.
     Location Differential
     Requests.
------------------------------------------------------------------------
\1\ The value is the sum of the Royalty Increase for the Rocky Mountain
  Region plus the mid point value of the ``Rest of the Country'' plus
  the mid point value of the Royalty Decrease for Increased Allowable
  Costs.
\2\ The low range impact is the sum of the Royalty Increase for the
  Rocky Mountain Region plus the lowest impact for the ``Rest of the
  Country'' plus the highest impact of the Royalty Decrease for
  Increased Allowable Costs. The high range impact is the sum of the
  Royalty Increase for the Rocky Mountain Region plus the highest impact
  for the ``Rest of the Country'' plus the lowest impact of the Royalty
  Decrease for Increased Allowable Costs. For example
  $11,738+$4,303,913+($9,651,863)=($5,336,212) is the low range impact
  for Industry.

2. Regulatory Planning and Review, Executive Order 12866

    Summary of Comments: One State suggested that the revenue impacts 
that would result constitute a significant regulatory action under 
Executive Order 12866.
    MMS Response: This rule does constitute a significant regulatory 
action under Executive Order 12866, but not because of the potential 
revenue impacts. It constitutes a significant regulatory action because 
it may raise novel legal or policy issues.
    In accordance with 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 
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. MMS evaluated the costs of 
this rule, and estimates that industry might incur additional 
administrative costs of approximately $283,000 in the first year of 
implementation, and $33,000 in additional administrative costs in 
subsequent years. The Federal Government might incur $33,000 each year 
in 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 either 
refine their oil or sell their oil to affiliated marketers. Small 
producers will continue to pay their royalties based on the proceeds 
they receive for the sale of their oil to third parties as they have 
done since 1988.
    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 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.

[[Page 24974]]

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.

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 Sec. Sec.  3(a) 
and 3(b)(2) of the Order.

9. Paperwork Reduction Act of 1995

    The Office of Management and Budget (OMB) has approved a new 
collection of information contained in this rule, entitled 30 CFR 206, 
subpart C, Federal Oil under 44 U.S.C. 3501 et seq., and assigned 
control number 1010-0157. The total hour burden currently approved 
under 1010-0157 is 1,608. The information collection applies only to 
Sec. Sec.  206.103(b)(4), 206.112(a)(1)(ii), 206.112(b)(3), and 
210.53(a) and (b) of this rule and the burden hours are allocated 
equally to each section. OMB approval of this collection expires 
October 31, 2006. We received comments from industry, but there were no 
changes in the information collection from the proposed rule to the 
final rule. We will use the information collected to ensure that proper 
royalty is paid on oil produced from Federal onshore and offshore 
leases.
    Submit your comments on the accuracy of this burden estimate or 
suggestions on reducing the burden to Sharron L. Gebhardt, Lead 
Regulatory Specialist, Chief of Staff Office, Minerals Revenue 
Management, MMS, PO Box 25165, MS 320B2, Denver, Colorado 80225. If you 
use an overnight courier service, the MMS courier address is Building 
85, Room A-614, Denver Federal Center, Denver, Colorado 80225. An 
agency may not conduct or sponsor, and a person is not required to 
respond to, a collection of information unless it displays a currently 
valid OMB control number.

10. National Environmental Policy Act (NEPA)

    This rule deals with financial matters and has no direct effect on 
Minerals Management Service decisions on environmental activities. 
Pursuant to the Department of the Interior Departmental Manual (DM), 
516 DM 2.3A (2), Sec.  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 22951) and DOI DM 512 DM 2, we have evaluated 
potential effects on federally recognized Indian tribes. This rule does 
not apply to Indian leases. However, these changes may have an impact 
on Indian leases. As such, by Federal Register notice (68 FR 7086) 
dated February 12, 2003, MMS reopened the comment period on the January 
2000 supplementary proposed rule for valuing crude oil produced from 
Indian leases. The comment period closed on April 14, 2003. MMS will 
determine how to proceed with that rulemaking based on comments 
received, taking into account our trust responsibilities and 
safeguarding the competitiveness of Indian leases.

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 oil 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.  204.200.
    (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 this 
rule?
    (7) What else could we do to make the rule easier to understand?

[[Page 24975]]

    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: March 17, 2004.
Chad Calvert,
Acting Assistant Secretary for Land and Minerals Management.

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

PART 206--PRODUCT VALUATION

0
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.


0
2. Section 206.101 is amended to:
0
a. Revise the introductory text and paragraph (2) of the definition of 
``affiliate.''
0
b. Remove the definitions of ``index pricing'' and ``index pricing 
point.''
0
c. Revise the definitions of ``MMS-approved publication'' and ``trading 
month.''
0
d. Add definitions of ``NYMEX price,'' ``prompt month,'' ``roll,'' and 
`` WTI differential.''
    The revisions and additions read as follows:


Sec.  206.101  What definitions apply to this subpart?

* * * * *
    Affiliate means a person who controls, is controlled by, or is 
under common control with another person. For purposes of this subpart:
* * * * *
    (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:
* * * * *
    MMS-approved publication means a publication MMS approves for 
determining ANS spot prices or WTI differentials.
* * * * *
    NYMEX price means the average of the New York Mercantile Exchange 
(NYMEX) settlement prices for light sweet crude oil delivered at 
Cushing, Oklahoma, calculated as follows:
    (1) Sum the prices published for each day during the calendar month 
of production (excluding weekends and holidays) for oil to be delivered 
in the prompt month corresponding to each such day; and
    (2) Divide the sum by the number of days on which those prices are 
published (excluding weekends and holidays).
* * * * *
    Prompt month means the nearest month of delivery for which NYMEX 
futures prices are published during the trading month.
* * * * *
    Roll means an adjustment to the NYMEX price that is calculated as 
follows:
    Roll = .6667 x (P0-P1) + .3333 x 
(P0-P2), where: P0 = the average of 
the daily NYMEX settlement prices for deliveries during the prompt 
month that is the same as the month of production, as published for 
each day during the trading month for which the month of production is 
the prompt month; P1 = the average of the daily NYMEX 
settlement prices for deliveries during the month following the month 
of production, published for each day during the trading month for 
which the month of production is the prompt month; and P2 = 
the average of the daily NYMEX settlement prices for deliveries during 
the second month following the month of production, as published for 
each day during the trading month for which the month of production is 
the prompt month. Calculate the average of the daily NYMEX settlement 
prices using only the days on which such prices are published 
(excluding weekends and holidays).
    (1) Example 1. Prices in Out Months are Lower Going Forward: The 
month of production for which you must determine royalty value is 
March. March was the prompt month (for year 2003) from January 22 
through February 20. April was the first month following the month of 
production, and May was the second month following the month of 
production. P0 therefore is the average of the daily NYMEX 
settlement prices for deliveries during March published for each 
business day between January 22 and February 20. P1 is the 
average of the daily NYMEX settlement prices for deliveries during 
April published for each business day between January 22 and February 
20. P2 is the average of the daily NYMEX settlement prices 
for deliveries during May published for each business day between 
January 22 and February 20. In this example, assume that P0 
= $28.00 per bbl, P1 = $27.70 per bbl, and P2 = 
$27.10 per bbl. In this example (a declining market), Roll = .6667 x 
($28.00-$27.70) + .3333 x ($28.00-$27.10) = $.20 + $.30 = $.50. You add 
this number to the NYMEX price.
    (2) Example 2. Prices in Out Months are Higher Going Forward: The 
month of production for which you must determine royalty value is July. 
July 2003 was the prompt month from May 21 through June 20. August was 
the first month following the month of production, and September was 
the second month following the month of production. P0 
therefore is the average of the daily NYMEX settlement prices for 
deliveries during July published for each business day between May 21 
and June 20. P1 is the average of the daily NYMEX settlement 
prices for deliveries during August published for each business day 
between May 21 and June 20. P2 is the average of the daily 
NYMEX settlement prices for deliveries during September published for 
each business day between May 21 and June 20. In this example, assume 
that P0 = $28.00 per bbl, P1 = $28.90 per bbl, 
and P2 = $29.50 per bbl. In this example (a rising market), 
Roll = .6667 x ($28.00-$28.90) + .3333 x ($28.00-$29.50) = (-$.60) + (-
$.50) = -$1.10. You add this negative number to the NYMEX price 
(effectively a subtraction from the NYMEX price).
* * * * *
    Trading month means the period extending from the second business 
day before the 25th day of the second calendar month preceding the 
delivery month (or, if the 25th day of that month is a non-business 
day, the second business day before the last business day preceding the 
25th day of that month) through the third business day before the 25th 
day of the calendar month preceding the delivery month (or, if the 25th 
day of that month is a non-business day, the third business day before 
the last business day preceding the 25th day of that month), unless the 
NYMEX publishes a different definition or different dates on its 
official Web site, www.nymex.com, in which case the NYMEX definition 
will apply.
* * * * *
    WTI differential means the average of the daily mean differentials 
for location and quality between a grade of crude oil at a market 
center and West Texas Intermediate (WTI) crude oil at Cushing published 
for each day for which price publications perform surveys for

[[Page 24976]]

deliveries during the production month, calculated over the number of 
days on which those differentials are published (excluding weekends and 
holidays). Calculate the daily mean differentials by averaging the 
daily high and low differentials for the month in the selected 
publication. Use only the days and corresponding differentials for 
which such differentials are published.
    (1) Example. Assume the production month was March 2003. Industry 
trade publications performed their price surveys and determined 
differentials during January 26 through February 25 for oil delivered 
in March. The WTI differential (for example, the West Texas Sour crude 
at Midland, Texas, spread versus WTI) applicable to valuing oil 
produced in the March 2003 production month would be determined using 
all the business days for which differentials were published during the 
period January 26 through February 25 excluding weekends and holidays 
(22 days). To calculate the WTI differential, add together all of the 
daily mean differentials published for January 26 through February 25 
and divide that sum by 22.
    (2) [Reserved]

0
3. In Sec.  206.103, paragraphs (b), (c), (d), and (e) introductory 
text, (e)(1)(ii), and (iii) are revised to read as follows:


Sec.  206.103  How do I value oil that is not sold under an arm's-
length contract?

* * * * *
    (b) Production from leases in the Rocky Mountain Region. This 
paragraph provides methods and options for valuing your production 
under different factual situations. You must consistently apply 
paragraph (b)(1), (b)(2), or (b)(3) of this section to value all of 
your production from the same unit, communitization agreement, or lease 
(if the lease or a portion of the lease is not part of a unit or 
communitization agreement) that you cannot value under Sec.  206.102 or 
that you elect under Sec.  206.102(d) to value under this section.
    (1) If you have an MMS-approved tendering program, you must value 
oil produced from leases in the area the tendering program covers at 
the highest winning bid price for tendered volumes.
    (i) The minimum requirements for MMS to approve your tendering 
program are:
    (A) You must offer and sell at least 30 percent of your or your 
affiliates' production from both Federal and non-Federal leases in the 
area under your tendering program; and
    (B) You must receive at least three bids for the tendered volumes 
from bidders who do not have their own tendering programs that cover 
some or all of the same area.
    (ii) If you do not have an MMS-approved tendering program, you may 
elect to value your oil under either paragraph (b)(2) or (b)(3) of this 
section. After you select either paragraph (b)(2) or (b)(3) of this 
section, you may not change to the other method more often than once 
every 2 years, unless the method you have been using is no longer 
applicable and you must apply the other paragraph. If you change 
methods, you must begin a new 2-year period.
    (2) Value is the volume-weighted average of the gross proceeds 
accruing to the seller under your or your affiliates' arm's-length 
contracts for the purchase or sale of production from the field or area 
during the production month.
    (i) The total volume purchased or sold under those contracts must 
exceed 50 percent of your and your affiliates' production from both 
Federal and non-Federal leases in the same field or area during that 
month.
    (ii) Before calculating the volume-weighted average, you must 
normalize the quality of the oil in your or your affiliates' arm's-
length purchases or sales to the same gravity as that of the oil 
produced from the lease.
    (3) Value is the NYMEX price (without the roll), adjusted for 
applicable location and quality differentials and transportation costs 
under Sec.  206.112.
    (4) If you demonstrate to MMS's satisfaction that paragraphs (b)(1) 
through (b)(3) of this section result in an unreasonable value for your 
production as a result of circumstances regarding that production, the 
MMS Director may establish an alternative valuation method.
    (c) Production from leases not located in California, Alaska, or 
the Rocky Mountain Region. (1) Value is the NYMEX price, plus the roll, 
adjusted for applicable location and quality differentials and 
transportation costs under Sec.  206.112.
    (2) If the MMS Director determines that use of the roll no longer 
reflects prevailing industry practice in crude oil sales contracts or 
that the most common formula used by industry to calculate the roll 
changes, MMS may terminate or modify use of the roll under paragraph 
(c)(1) of this section at the end of each 2-year period following July 
6, 2004, through notice published in the Federal Register not later 
than 60 days before the end of the 2-year period. MMS will explain the 
rationale for terminating or modifying the use of the roll in this 
notice.
    (d) Unreasonable value. If MMS determines that the NYMEX price or 
ANS spot price does not represent a reasonable royalty value in any 
particular case, MMS may establish reasonable royalty value based on 
other relevant matters.
    (e) Production delivered to your refinery and the NYMEX price or 
ANS spot price is an unreasonable value.
    (1) * * *
    (ii) You must value your oil under this section at the NYMEX price 
or ANS spot price; and
    (iii) You believe that use of the NYMEX price or ANS spot price 
results in an unreasonable royalty value.
* * * * *


0
4. In Sec.  206.104, the section heading, the introductory text of 
paragraph (a), and paragraphs (a)(3), (c), and (d) are revised to read 
as follows:


Sec.  206.104  What publications are acceptable to MMS?

    (a) MMS periodically will publish in the Federal Register a list of 
acceptable publications for the NYMEX price and ANS spot price based on 
certain criteria, including, but not limited to:
* * * * *
    (3) Publications that use adequate survey techniques, including 
development of estimates based on daily surveys of buyers and sellers 
of crude oil, and, for ANS spot prices, buyers and sellers of ANS crude 
oil; and
* * * * *
    (c) MMS will specify the tables you must use in the acceptable 
publications.
    (d) MMS may revoke its approval of a particular publication if it 
determines that the prices or differentials published in the 
publication do not accurately represent NYMEX prices or differentials 
or ANS spot market prices or differentials.


0
5. In Sec.  206.109, paragraph (b) is revised to read as follows:


Sec.  206.109  When may I take a transportation allowance in 
determining value?

* * * * *
    (b) Transportation allowances and other adjustments that apply when 
value is based on NYMEX prices or ANS spot prices. If you value oil 
using NYMEX prices or ANS spot prices under Sec.  206.103, MMS will 
allow an adjustment for certain location and quality differentials and 
certain costs associated with transporting oil as provided under Sec.  
206.112.
* * * * *


0
6. Section 206.110 is amended by:
0
A. Revising paragraph (a);

[[Page 24977]]

0
B. Redesignating existing paragraphs (b) through (e) as paragraphs (d) 
through (g); and
0
C. Adding new paragraphs (b) and (c).
    The revisions and additions read as follows:


Sec.  206.110  How do I determine a transportation allowance under an 
arm's-length transportation contract?

    (a) If you or your affiliate incur transportation costs under an 
arm's-length transportation contract, you may claim a transportation 
allowance for the reasonable, actual costs incurred as more fully 
explained in paragraph (b) of this section, except as provided in 
paragraphs (a)(1) and (a)(2) of this section and subject to the 
limitation in Sec.  206.109(c). You must be able to demonstrate that 
your or your affiliate's contract is at arm's length. You do not need 
MMS approval before reporting a transportation allowance for costs 
incurred under an arm's-length transportation contract.
* * * * *
    (b) You may deduct any of the following actual costs you (including 
your affiliates) incur for transporting oil. You may not use as a 
deduction any cost that duplicates all or part of any other cost that 
you use under this paragraph.
    (1) The amount that you pay under your arm's-length transportation 
contract or tariff.
    (2) Fees paid (either in volume or in value) for actual or 
theoretical line losses.
    (3) Fees paid for administration of a quality bank.
    (4) The cost of carrying on your books as inventory a volume of oil 
that the pipeline operator requires you to maintain, and that you do 
maintain, in the line as line fill. You must calculate this cost as 
follows:
    (i) Multiply the volume that the pipeline requires you to maintain, 
and that you do maintain, in the pipeline by the value of that volume 
for the current month calculated under Sec.  206.102 or Sec.  206.103, 
as applicable; and
    (ii) Multiply the value calculated under paragraph (b)(4)(i) of 
this section by the monthly rate of return, calculated by dividing the 
rate of return specified in Sec.  206.111(i)(2) by 12.
    (5) Fees paid to a terminal operator for loading and unloading of 
crude oil into or from a vessel, vehicle, pipeline, or other 
conveyance.
    (6) Fees paid for short-term storage (30 days or less) incidental 
to transportation as required by a transporter.
    (7) Fees paid to pump oil to another carrier's system or vehicles 
as required under a tariff.
    (8) Transfer fees paid to a hub operator associated with physical 
movement of crude oil through the hub when you do not sell the oil at 
the hub. These fees do not include title transfer fees.
    (9) Payments for a volumetric deduction to cover shrinkage when 
high-gravity petroleum (generally in excess of 51 degrees API) is mixed 
with lower-gravity crude oil for transportation.
    (10) Costs of securing a letter of credit, or other surety, that 
the pipeline requires you as a shipper to maintain.
    (c) You may not deduct any costs that are not actual costs of 
transporting oil, including but not limited to the following:
    (1) Fees paid for long-term storage (more than 30 days).
    (2) Administrative, handling, and accounting fees associated with 
terminalling.
    (3) Title and terminal transfer fees.
    (4) Fees paid to track and match receipts and deliveries at a 
market center or to avoid paying title transfer fees.
    (5) Fees paid to brokers.
    (6) Fees paid to a scheduling service provider.
    (7) 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.
    (8) Gauging fees.
* * * * *

0
7. Section 206.111 is amended by:
0
A. Revising the section heading and paragraph (a);
0
B. In paragraph (b), revising the introductory text and adding new 
paragraphs (b)(6) and (b)(7);
0
C. Revising paragraph (h)(5); and
0
D. Revising paragraph (i)(2).
    The amendments read as follows:


Sec.  206.111  How do I determine a transportation allowance if I do 
not have an arm's-length transportation contract or arm's-length 
tariff?

    (a) This section applies if you or your affiliate do not have an 
arm's-length transportation contract, including situations where you or 
your affiliate provide your own transportation services. Calculate your 
transportation allowance based on your or your affiliate's reasonable, 
actual costs for transportation during the reporting period using the 
procedures prescribed in this section.
    (b) Your or your affiliate's actual costs include the following:
* * * * *
    (6) To the extent not included in costs identified in paragraphs 
(d) through (j) of this section, you may also deduct the following 
actual costs. You may not use any cost as a deduction that duplicates 
all or part of any other cost that you use under this section:
    (i) Volumetric adjustments for actual (not theoretical) line 
losses.
    (ii) The cost of carrying on your books as inventory a volume of 
oil that the pipeline operator requires you as a shipper to maintain, 
and that you do maintain, in the line as line fill. You must calculate 
this cost as follows:
    (A) Multiply the volume that the pipeline requires you to maintain, 
and that you do maintain, in the pipeline by the value of that volume 
for the current month calculated under Sec.  206.102 or Sec.  206.103, 
as applicable; and
    (B) Multiply the value calculated under paragraph (b)(6)(ii)(A) of 
this section by the monthly rate of return, calculated by dividing the 
rate of return specified in Sec.  206.111(i)(2) by 12.
    (iii) Fees paid to a non-affiliated terminal operator for loading 
and unloading of crude oil into or from a vessel, vehicle, pipeline, or 
other conveyance.
    (iv) Transfer fees paid to a hub operator associated with physical 
movement of crude oil through the hub when you do not sell the oil at 
the hub. These fees do not include title transfer fees.
    (v) A volumetric deduction to cover shrinkage when high-gravity 
petroleum (generally in excess of 51 degrees API) is mixed with lower-
gravity crude oil for transportation.
    (vi) Fees paid to a non-affiliated quality bank administrator for 
administration of a quality bank.
    (7) You may not deduct any costs that are not actual costs of 
transporting oil, including but not limited to the following:
    (i) Fees paid for long-term storage (more than 30 days).
    (ii) Administrative, handling, and accounting fees associated with 
terminalling.
    (iii) Title and terminal transfer fees.
    (iv) Fees paid to track and match receipts and deliveries at a 
market center or to avoid paying title transfer fees.
    (v) Fees paid to brokers.
    (vi) Fees paid to a scheduling service provider.
    (vii) 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.
    (viii) Theoretical line losses.
    (ix) Gauging fees.
    (h) * * *

[[Page 24978]]

    (5) If you or your affiliate purchase a transportation system at 
arm's length after June 1, 2000, from anyone other than the original 
owner, you must assume the depreciation schedule of the person from 
whom you bought the system. Include in the depreciation schedule any 
subsequent reinvestment.
    (i) * * *
    (2) The rate of return is 1.3 times the industrial bond yield index 
for Standard & Poor's BBB bond rating. Use the monthly average rate 
published in ``Standard & Poor's Bond Guide'' for the first month of 
the reporting period for which the allowance applies. Calculate the 
rate at the beginning of each subsequent transportation allowance 
reporting period.
* * * * *


0
8. Section 206.112 is revised to read as follows:


Sec.  206.112  What adjustments and transportation allowances apply 
when I value oil production from my lease using NYMEX prices or ANS 
spot prices?

    This section applies when you use NYMEX prices or ANS spot prices 
to calculate the value of production under Sec.  206.103. As specified 
in this section, adjust the NYMEX price to reflect the difference in 
value between your lease and Cushing, Oklahoma, or adjust the ANS spot 
price to reflect the difference in value between your lease and the 
appropriate MMS-recognized market center at which the ANS spot price is 
published (for example, Long Beach, California, or San Francisco, 
California). Paragraph (a) of this section explains how you adjust the 
value between the lease and the market center, and paragraph (b) of 
this section explains how you adjust the value between the market 
center and Cushing when you use NYMEX prices. Paragraph (c) of this 
section explains how adjustments may be made for quality differentials 
that are not accounted for through exchange agreements. Paragraph (d) 
of this section gives some examples. References in this section to 
``you'' include your affiliates as applicable.
    (a) To adjust the value between the lease and the market center:
    (1)(i) For oil that you exchange at arm's length between your lease 
and the market center (or between any intermediate points between those 
locations), you must calculate a lease-to-market center differential by 
the applicable location and quality differentials derived from your 
arm's-length exchange agreement applicable to production during the 
production month.
    (ii) For oil that you exchange between your lease and the market 
center (or between any intermediate points between those locations) 
under an exchange agreement that is not at arm's length, you must 
obtain approval from MMS for a location and quality differential. Until 
you obtain such approval, you may use the location and quality 
differential derived from that exchange agreement applicable to 
production during the production month. If MMS prescribes a different 
differential, you must apply MMS's differential to all periods for 
which you used your proposed differential. You must pay any additional 
royalties owed resulting from using MMS's differential plus late 
payment interest from the original royalty due date, or you may report 
a credit for any overpaid royalties plus interest under 30 U.S.C. 
1721(h).
    (2) For oil that you transport between your lease and the market 
center (or between any intermediate points between those locations), 
you may take an allowance for the cost of transporting that oil between 
the relevant points as determined under Sec.  206.110 or Sec.  206.111, 
as applicable.
    (3) If you transport or exchange at arm's length (or both transport 
and exchange) at least 20 percent, but not all, of your oil produced 
from the lease to a market center, determine the adjustment between the 
lease and the market center for the oil that is not transported or 
exchanged (or both transported and exchanged) to or through a market 
center as follows:
    (i) Determine the volume-weighted average of the lease-to-market 
center adjustment calculated under paragraphs (a)(1) and (a)(2) of this 
section for the oil that you do transport or exchange (or both 
transport and exchange) from your lease to a market center.
    (ii) Use that volume-weighted average lease-to-market center 
adjustment as the adjustment for the oil that you do not transport or 
exchange (or both transport and exchange) from your lease to a market 
center.
    (4) If you transport or exchange (or both transport and exchange) 
less than 20 percent of the crude oil produced from your lease between 
the lease and a market center, you must propose to MMS an adjustment 
between the lease and the market center for the portion of the oil that 
you do not transport or exchange (or both transport and exchange) to a 
market center. Until you obtain such approval, you may use your 
proposed adjustment. If MMS prescribes a different adjustment, you must 
apply MMS's adjustment to all periods for which you used your proposed 
adjustment. You must pay any additional royalties owed resulting from 
using MMS's adjustment plus late payment interest from the original 
royalty due date, or you may report a credit for any overpaid royalties 
plus interest under 30 U.S.C. 1721(h).
    (5) You may not both take a transportation allowance and use a 
location and quality adjustment or exchange differential for the same 
oil between the same points.
    (b) For oil that you value using NYMEX prices, adjust the value 
between the market center and Cushing, Oklahoma, as follows:
    (1) If you have arm's-length exchange agreements between the market 
center and Cushing under which you exchange to Cushing at least 20 
percent of all the oil you own at the market center during the 
production month, you must use the volume-weighted average of the 
location and quality differentials from those agreements as the 
adjustment between the market center and Cushing for all the oil that 
you produce from the leases during that production month for which that 
market center is used.
    (2) If paragraph (b)(1) of this section does not apply, you must 
use the WTI differential published in an MMS-approved publication for 
the market center nearest your lease, for crude oil most similar in 
quality to your production, as the adjustment between the market center 
and Cushing. (For example, for light sweet crude oil produced offshore 
of Louisiana, use the WTI differential for Light Louisiana Sweet crude 
oil at St. James, Louisiana.) After you select an MMS-approved 
publication, you may not select a different publication more often than 
once every 2 years, unless the publication you use is no longer 
published or MMS revokes its approval of the publication. If you are 
required to change publications, you must begin a new 2-year period.
    (3) If neither paragraph (b)(1) nor (b)(2) of this section applies, 
you may propose an alternative differential to MMS. Until you obtain 
such approval, you may use your proposed differential. If MMS 
prescribes a different differential, you must apply MMS's differential 
to all periods for which you used your proposed differential. You must 
pay any additional royalties owed resulting from using MMS's 
differential plus late payment interest from the original royalty due 
date, or you may report a credit for any overpaid royalties plus 
interest under 30 U.S.C. 1721(h).
    (c)(1) If you adjust for location and quality differentials or for 
transportation costs under paragraphs (a) and (b) of this section, also 
adjust the NYMEX price or ANS spot price for quality based on premiums 
or penalties determined by pipeline quality bank

[[Page 24979]]

specifications at intermediate commingling points or at the market 
center if those points are downstream of the royalty measurement point 
approved by MMS or BLM, as applicable. Make this adjustment only if and 
to the extent that such adjustments were not already included in the 
location and quality differentials determined from your arm's-length 
exchange agreements.
    (2) If the quality of your oil as adjusted is still different from 
the quality of the representative crude oil at the market center after 
making the quality adjustments described in paragraphs (a), (b) and 
(c)(1) of this section, you may make further gravity adjustments using 
posted price gravity tables. If quality bank adjustments do not 
incorporate or provide for adjustments for sulfur content, you may make 
sulfur adjustments, based on the quality of the representative crude 
oil at the market center, of 5.0 cents per one-tenth percent difference 
in sulfur content, unless MMS approves a higher adjustment.
    (d) The examples in this paragraph illustrate how to apply the 
requirement of this section.
    (1) Example. Assume that a Federal lessee produces crude oil from a 
lease near Artesia, New Mexico. Further, assume that the lessee 
transports the oil to Roswell, New Mexico, and then exchanges the oil 
to Midland, Texas. Assume the lessee refines the oil received in 
exchange at Midland. Assume that the NYMEX price is $30.00/bbl, 
adjusted for the roll; that the WTI differential (Cushing to Midland) 
is -$.10/bbl; that the lessee's exchange agreement between Roswell and 
Midland results in a location and quality differential of -$.08/bbl; 
and that the lessee's actual cost of transporting the oil from Artesia 
to Roswell is $.40/bbl. In this example, the royalty value of the oil 
is $30.00-$.10-$.08--$.40 = $29.42/bbl.
    (2) Example. Assume the same facts as in the example in paragraph 
(1), except that the lessee transports and exchanges to Midland 40 
percent of the production from the lease near Artesia, and transports 
the remaining 60 percent directly to its own refinery in Ohio. In this 
example, the 40 percent of the production would be valued at $29.42/
bbl, as explained in the previous example. In this example, the other 
60 percent also would be valued at $29.42/bbl.
    (3) Example. Assume that a Federal lessee produces crude oil from a 
lease near Bakersfield, California. Further, assume that the lessee 
transports the oil to Hynes Station, and then exchanges the oil to 
Cushing which it further exchanges with oil it refines. Assume that the 
ANS spot price is $20.00/bbl, and that the lessee's actual cost of 
transporting the oil from Bakersfield to Hynes Station is $.28/bbl. The 
lessee must request approval from MMS for a location and quality 
adjustment between Hynes Station and Long Beach. For example, the 
lessee likely would propose using the tariff on Line 63 from Hynes 
Station to Long Beach as the adjustment between those points. Assume 
that adjustment to be $.72, including the sulfur and gravity bank 
adjustments, and that MMS approves the lessee's request. In this 
example, the preliminary (because the location and quality adjustment 
is subject to MMS review) royalty value of the oil is $20.00-$.72-$.28 
= $19.00/bbl. The fact that oil was exchanged to Cushing does not 
change use of ANS spot prices for royalty valuation.


Sec.  206.118  [Removed]

0
9. Section 206.118 is removed.


0
10. Paragraph (c) of Sec.  206.119 is revised to read as follows:


Sec.  206.119  How are royalty quantity and quality determined?

* * * * *
    (c) Any actual loss that you may incur before the royalty 
settlement metering or measurement point is not subject to royalty if 
BLM or MMS, as appropriate, determines that the loss is unavoidable.
* * * * *


Sec.  206.121  [Removed]

0
11. Section 206.121 is removed.

[FR Doc. 04-10083 Filed 5-4-04; 8:45 am]
BILLING CODE 4310-MR-P