[Federal Register Volume 68, Number 161 (Wednesday, August 20, 2003)]
[Proposed Rules]
[Pages 50087-50108]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 03-21217]


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DEPARTMENT OF THE INTERIOR

Minerals Management Service

30 CFR Part 206 and 210

RIN 1010-AD04


Federal Oil Valuation

AGENCY: Minerals Management Service (MMS), Interior.

ACTION: Proposed rule.

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SUMMARY: The MMS is proposing to amend 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.
    Experience thus far has shown that the 2000 rules have generally 
served both MMS (and the states who cooperate with MMS in auditing 
Federal leases) and the producing industry well. However, in continuing 
to evaluate the effectiveness and efficiency of its rules, MMS has 
identified certain issues that warrant further proposal and public 
comment. These issues concern primarily which published market

[[Page 50088]]

prices are most appropriate to value crude oil not sold at arm's length 
and what transportation deductions should be allowed. Experience thus 
far with the 2000 rules, some years of experience in taking and selling 
royalty-in-kind oil, and information learned during litigation 
challenging the 2000 rules indicate a potential for improving those 
rules in some respects.

DATES: Comments must be submitted on or before September 19, 2003.

ADDRESSES: Address your comments, suggestions, or objections regarding 
this proposed rule to:
    By regular U.S. mail. Minerals Management Service, Minerals Revenue 
Management, Records and Information Management Team, P.O. Box 25165, MS 
320B2, Denver, Colorado 80225-0165; or
    By overnight mail or courier. Minerals Management Service, Minerals 
Revenue Management, Building 85, Room A-614, Denver Federal Center, 
Denver, Colorado 80225; or
    By e-mail. [email protected]. Please submit Internet comments as 
an ASCII file and avoid the use of special characters and any form of 
encryption. Also, please include ``Attn: RIN 1010-AD04'' and your name 
and return address in your Internet message. If you do not receive a 
confirmation that we have received your Internet message, call the 
contact person listed below.
    Address your comments on the information collection requirements in 
this proposed rule by either fax (202) 395-6566 or e-mail ([email protected]) to the Office of Information and Regulatory 
Affairs, OMB, Attention: Desk Officer for the Department of the 
Interior (OMB Control Number 1010-NEW). Send copies of your comments to 
Sharron L. Gebhardt, Regulatory Specialist, Records and Information 
Management Team, Minerals Management Service, Minerals Revenue 
Management, P.O. 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. You may 
also e-mail your comments to us at [email protected]. Include the 
title of the information collection and the OMB Control number in the 
``Attention'' line of your comment. Also include your name and return 
address. Submit electronic comments as an ASCII file avoiding the use 
of special characters and any form of encryption. If you do not receive 
a confirmation that we have received your e-mail, contact Ms. Gebhardt 
at (303) 231-3211.

FOR FURTHER INFORMATION CONTACT: Sharron L. Gebhardt, Regulatory 
Specialist, Records and Information Management Team, Minerals Revenue 
Management, MMS, telephone (303) 231-3316, fax (303) 231-3385, or e-
mail [email protected]. The principal authors of this rule are 
Geoffrey Heath of the Office of the Solicitor and David A. Hubbard of 
Minerals Revenue Management, MMS, Department of the Interior.

SUPPLEMENTARY INFORMATION:

I. Background

    The MMS is proposing to amend the existing regulations at 30 CFR 
206.100 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. The producing industry filed a lawsuit challenging several of 
the provisions in the 2000 rule. Independent Petroleum Association of 
America v. Baca, Civil No. 00-761 (RCL) (D.D.C.), and American 
Petroleum Institute v. Baca, Civil No. 00-887 (RCL) (D.D.C.) 
(consolidated). That lawsuit is still pending.
    MMS conducted four public workshops on March 4-6, 2003, in Denver, 
Colorado; Albuquerque, New Mexico; Houston, Texas; and Washington, DC. 
At those workshops, MMS asked for discussion regarding, among other 
things, the best published index to use in valuing production not sold 
at arm's length and related timing issues, greater specificity 
regarding allowable transportation costs, the rate of return on 
undepreciated capital investment in calculating actual transportation 
costs, and the royalty effect of sales under joint operating 
agreements. After considering the input from these workshops, MMS is 
proposing these amendments in an effort to improve the current rule.
    The amendments proposed do not alter the basic structure or 
underlying principles of the June 2000 rule. In proposing these 
amendments, the Department of the Interior reaffirms that the value for 
royalty purposes of crude oil produced from Federal leases is value at 
or near the lease. But in determining value at the lease of production 
not sold under an arm's-length contract at the lease, 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 (D.C. Cir. 2002), cert. denied sub nom., 
Independent Petroleum Association of America, et al. v. Watson, --
U.S.--, 123 S. Ct. 869 (Jan. 13, 2003).
    In the following discussion, we group the proposed changes by issue 
category and discuss the specific proposed changes to specific sections 
of the rule in that context.

A. Change to NYMEX-Based Valuation--Sec.  206.103

1. Determining the NYMEX Price To Use for Valuation
    For crude oil not sold at arm's length, the existing rule at Sec.  
206.103 provides for the use of spot prices at defined market centers 
published in approved publications both of which are listed in Federal 
Register Notices available on the MMS Internet site at http://www.mrm.mms.gov/Laws_R_D/FRNotices/, as the basis for valuation of 
crude oil for most of the country except the Rocky Mountain Region. (In 
the Rocky Mountain Region, spot prices are the basis for the third 
``benchmark.'') Our experience with the rule and comments we have 
received lead us to believe that, at this time, New York Mercantile 
Exchange (NYMEX) futures prices may 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 may have 
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.

[[Page 50089]]

    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. This is not true for 
California, where all the days in the calendar month preceding the 
month of delivery are used to assess spot prices applicable to the 
month of delivery.
    MMS has studied 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. These studies demonstrate that calendar-month 
NYMEX prices (applying the ``roll'', ( as discussed below, to Gulf of 
Mexico, mid-continent, and Permian Basin production) have the highest 
correlation to reported arm's-length sales values of any publicly-
available indices. We have examined both onshore and Gulf of Mexico 
crude oil types, and this conclusion applies to both.
    Under the proposed rule, the ``initial'' or ``base'' NYMEX price 
that would be used to value production in a given production month is 
calculated by averaging the daily NYMEX settlement prices for each 
trading day in that month for deliveries in the first future month 
(known as the ``prompt month''), excluding weekends and holidays. The 
prompt month changes during the production month so that in the 
beginning of the month the prompt month is the first month after the 
month of production. According to the NYMEX rules, trading ends at the 
close of business on the third business day prior to the 25th calendar 
day of the month (or the first business day prior to the 25th) 
preceding the delivery month. After that date the prompt month becomes 
the second month after the production month. See the NYMEX Web site for 
the specifications: http://www.nymex.com/jsp/markets/lsco_fut_specif.jsp.
    We are proposing to exclude weekends and holidays for two reasons. 
First, if we include weekends and holidays, we would need to assign a 
price from other days on which trades actually take place. The normal 
way to do this is to use the preceding day's price (usually Friday's) 
on the assumption that that is the most accurate reflection of the 
price for deliveries that take place on the weekend. However, that 
results in weighting Fridays three times as much as other days. MMS 
does not believe there is a justification for overweighting Friday 
prices. The second reason that MMS is proposing to exclude weekends and 
holidays is that it is MMS's understanding that it is more common 
industry practice to exclude them in calculating monthly average prices 
on the NYMEX.
    For example, to value production from Federal leases in March 2003 
using NYMEX prices, you would average the NYMEX settlement prices 
published each business day in March, between March 1 and March 22, for 
April 2003, and between March 23 and 31 for May 2003. Importantly, this 
calculation is based on ``trading days during the calendar month.'' 
This is different from ``trading month,'' which is a term of art 
defined in these rules, as discussed below.
    The 2000 rule uses prices assessed for the trading period that is 
as close to concurrent with the production month as possible. However, 
we've received comments that this period this is not consistent with 
the way industry does business. Under this proposal, the daily NYMEX 
prices used correspond more closely to the production month than under 
the existing rule.
    MMS is proposing to apply a ``roll'' to the initial NYMEX oil 
prices from leases in the Gulf of Mexico and the mid-continent, 
including the Permian Basin. The ``roll'' is a commonly used measure of 
the trend of NYMEX prices for future deliveries in those areas. 
Proposing use of the roll necessitates proposing to change the 
definition of ``trading month.'' In section 206.101 of the current 
rule, ``trading month'' is defined in terms of spot market sales. 
Because the NYMEX price is the measure of value under the proposed 
rule, and because MMS proposes to use the roll, MMS proposes to change 
the definition of ``trading month'' to conform with NYMEX definitions 
and practice.
    MMS proposes to define trading month to mean 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, http://www.nymex.com, in 
which case the NYMEX definition will apply.
    Prices reported for futures contracts on the NYMEX are not limited 
to deliveries in the prompt month. 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 is 
necessary in order 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 the market is 
falling (to correct for the fact that the current price should be 
higher than the future price in a falling market) and subtracted from 
the initial NYMEX prices when the market is rising (to correct for the 
fact that the current price should be lower than the future price if 
the market is rising). We are proposing to use the roll because we 
believe it represents current market practice in establishing the sales 
price for crude oil production in certain regions of the country.
    The roll formula includes the future prices for the two months 
beyond the prompt month, which is not the same as the prompt month used 
to determine the initial NYMEX price and assigns a progressively 
smaller weight to the second and third months. This is consistent with 
MMS's understanding of the common industry practice, including the 
weights and basis for the prices in the formula below. Specifically, 
the roll is calculated as follows:

Roll=.6667 x (P0-P1) + .3333 x (P0-
P2), where

    [sbull] 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.
    [sbull] P1=the average of the daily NYMEX settlement 
prices for deliveries during the 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.
    [sbull] 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.

[[Page 50090]]

    Note that although prices P0, P1, and 
P2 represent separate prices for periods 1, 2, and 3 months 
beyond the trading month, respectively, they are all determined during 
the same trading month. The roll may be a positive or a negative 
number, and, therefore, increase or decrease the royalty value, 
depending on whether the futures market is falling or rising.
    For example, assume that the month of production for which you must 
determine royalty value is March 2003. March was the prompt month on 
the NYMEX (for year 2003) from January 22 through February 20, which is 
the trading month in this case. April is the first month following the 
month of production, and May is the second month following the month of 
production. As explained above, to determine the initial NYMEX price 
which the roll will adjust, for March 2003 production you first take 
the average of the daily settlement prices published for each business 
day from March 1 through March 20 for deliveries in April (the prompt 
month) and for each business day from March 21 through March 31 for 
deliveries in May (after May becomes the prompt month).
    To calculate P0, a different set of days is used. 
P0 is the average of the daily NYMEX settlement prices for 
deliveries during March published for each business day between January 
22 and February 20 (the trading month). P1 is the average of 
the daily NYMEX settlement prices for deliveries during April published 
for each business day during the same trading month (i.e., between 
January 22 and February 20). Similarly, P2 is the average of 
the daily NYMEX settlement prices for deliveries during May published 
for each business day during the same trading month used for 
P0 and P1. In this example, assume that 
P0 = $28.00 per bbl, P1 = $27.70 per bbl, and 
P2 = $27.10 per bbl. In this declining market, the roll = 
.6667 x ($28.00 minus; 27.70) + .3333 x ($28.00 - 27.10) = $.20 + $.30 
= $.50. Fifty cents per barrel would then be added to the initial NYMEX 
settlement price used as the basis for royalty valuation. We have 
developed an illustration of this example and others which are 
available on the MMS Web site at http://www.mrm.mms.gov/OilVal/ValGuid.htm.
    In this example, since the market is falling, prices that traders 
anticipate during the trading month (March) for deliveries in a future 
prompt month are lower than the prices at which oil actually is selling 
during March. The roll accounts for that trend. The roll will have the 
opposite effect in a rising market. The roll will be a subtraction from 
the initial NYMEX price calculation (adding a negative number to the 
NYMEX price) because traders anticipate higher prices for the future 
prompt months than actually are occurring during the calendar month of 
production.
    The roll would be added to the initial NYMEX price used as the 
basis for royalty valuation, except for leases in California, Alaska, 
and the Rocky Mountain Region. The reason for this limitation is that 
at the workshops, industry representatives stated that they use the 
roll primarily for Gulf of Mexico and mid-continent production, and not 
for production in California, Alaska, or the Rocky Mountain Region.
    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. Therefore, MMS proposes that 
the Director of MMS would have the option of terminating use of the 
roll when MMS believes that using the roll is no longer a common 
industry practice at the end of each two-year period following the 
effective date of this paragraph through notice published in the 
Federal Register no later than 60 days before the end of the two-year 
period. Further, MMS also proposes to 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 the two-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. MMS specifically requests comments on whether this is 
appropriate, and whether a two-year period is appropriate.
    MMS is proposing to use NYMEX-based value as the basic measure of 
value for production not sold at arm's length in all areas except for 
the Rocky Mountain Region, where MMS proposes to use it as the revised 
third benchmark (proposed to be redesignated as section 206.103(b)(3)). 
As discussed earlier, the roll would not be added to the NYMEX price in 
the Rocky Mountain Region since its use does not reflect current 
industry practice there. The base NYMEX price would be adjusted for 
location and quality differentials and actual transportation costs back 
to the lease, as explained below.
2. Adjusting the NYMEX Price for Transportation Costs and Location and 
Quality Differentials
    Under the 2000 rule, market center index (spot) prices are adjusted 
to determine the value of production at the lease through location and 
quality differentials and deduction of actual transportation costs. See 
30 CFR Sec.  206.103 and 206.112. Location and quality differentials 
are derived from lessees' own arm's-length exchange agreements or, if 
exchanges are not at arm's-length, through MMS approval. Actual 
transportation costs from the lease to a market center or intermediate 
exchange point are determined under 30 CFR Sec.  206.110 and 206.111 
according to whether transportation arrangements are arm's-length or 
non-arm's-length.
    Adopting the NYMEX price as the basis for royalty valuation 
requires an additional adjustment beyond those in the current rule 
because the NYMEX price is defined only at Cushing, Oklahoma for light 
sweet crude oil. Therefore, differentials from Cushing to market 
centers other than Cushing are necessary. MMS believes that many 
lessees do not have arm's-length exchange agreements between each 
market center to which they transport or trade and Cushing. Therefore, 
MMS proposes to allow the use of published differentials when lessees 
do not exchange oil to Cushing at arm's length. Accordingly, MMS 
proposes to define a new term, ``WTI differential,'' as follows:

    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, Oklahoma, 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). 
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.

    Example. Assume the production month is March 2003. Industry trade 
publications perform their price surveys and determine differentials 
during January 26 through February 25 for oil delivered in March. 
(California is an exception. In California, the survey covers the 
calendar month of February for March deliveries.) 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

[[Page 50091]]

the business days for which differentials are published during the 
period January 26 through February 25. Note, in this example, that the 
days used in the monthly average calculation of the WTI differential 
are different than the days used to calculate the NYMEX price and are 
different than the days used to calculate the roll.
    This definition is intended to allow the lessee a method of 
calculating an accurate price at a market center near the lease so that 
crude oil produced from the lease can be accurately valued. The price 
at each market center would be the average of the daily NYMEX 
settlement prices published during the calendar month of production 
(including the roll, if applicable) plus or minus the appropriate WTI 
published differential. The lessee would then calculate a further 
differential from the market center to the lease.
    For example, if a producer does not have an arm's-length exchange 
agreement to Cushing, and the applicable NYMEX price (including the 
roll) is $29.00/bbl, and the WTI differential for Light Louisiana Sweet 
(LLS) crude oil is plus $.30/bbl at St. James, Louisiana, the value at 
St. James would be $29.30. That value must be further adjusted from the 
market center to the lease by applicable location and quality 
differentials and for actual transportation costs between the lease and 
the market center.
    Continuing the example, if a lessee produced Eugene Island (EI) 
sour crude and transported it from the lease to Burns Terminal at a 
cost of $1.19 per barrel, where it exchanged it at arm's length for LLS 
at St. James on the basis of $27.50/bbl for the EI crude and $28.80/bbl 
for the LLS, the value of the EI crude would be $29.30 (the LLS value 
at St. James) less the location and quality differential from the 
exchange agreement ($1.30), or $28.00. The lessee could then take the 
transportation allowance of $1.19 to get a value of $26.81 at the 
lease.
    Changing from spot market index price-based valuation to NYMEX-
based valuation and adding a definition for ``WTI differential'' would 
require a revision in the definition of ``MMS-approved publication.'' 
In the context of the proposed valuation scheme, and because NYMEX 
prices are widely available, the only context in which MMS approval of 
a publication would be needed is for determining the WTI differential. 
Accordingly, the proposed rule would revise the definition of ``MMS-
approved publication'' to read:
    MMS-approved publication means a publication MMS approves for 
determining WTI differentials.
3. Specific Comments Requested
    MMS requests specific comments about changing the valuation basis 
for transactions not at arm's length from spot to NYMEX prices, and to 
a calendar month average of such prices. MMS also requests specific 
comments on whether weekends and holidays should be included in the 
calculation of the average NYMEX price (and, if so, what price should 
be assigned to days on which no price is published). Further, MMS 
requests comments on whether it should include the ``roll'' in the 
calculation of the proper NYMEX price and whether the roll should apply 
only to areas other than California, Alaska, and the Rocky Mountain 
Region. MMS also requests comments on (1) whether lessees should use 
the location and quality differentials in their own arm's-length 
exchange agreements between Cushing and the lease or market center in 
preference to WTI differentials and (2) the circumstances under which 
they should use one or the other.
    Under proposed section 206.103(a), for leases in California and 
Alaska, you must adjust the NYMEX price for applicable location and 
quality differentials and you may adjust for actual transportation 
costs, as described at section 206.112. MMS also requests comments on 
whether it should retain ANS spot prices as the valuation basis for 
crude oil produced in California and Alaska instead of changing the 
valuation basis to the NYMEX price.

B. Determining Differentials When Using NYMEX-Based Valuation When 
Lessees Do Not Have Information From Their Own Exchange Agreements--
Sec. Sec.  206.103 and 206.104

    Based on requests we have received for valuation guidance and 
future valuation agreements for the Rocky Mountain Region, as well as 
our experience with RIK in that area, we believe that very few 
producers in the Rocky Mountain Region have actual trades of crude to 
Cushing. The same situation may apply to production in other areas, 
especially California. Therefore, in many cases producers do not have 
access to information to make adjustments to a price at Cushing. MMS 
therefore is proposing a change in how location and quality adjustments 
are made when you don't have an actual location and quality 
differential between Cushing and either the lease or a location to 
which you actually transport or exchange the oil.
    For example, in the Rocky Mountain Region for sweet crude oil 
produced from leases in Wyoming, the market center would be Guernsey, 
Wyoming. Under the proposed rule, you would use the WTI differential 
for Wyoming Sweet at Guernsey for sweet crude oil, as published in an 
MMS-approved publication. If you use the WTI differential for Wyoming 
Sweet at Guernsey, and you transport your oil to Guernsey, you may also 
subtract actual transportation costs from the lease to Guernsey. If you 
exchange your oil from the lease to Guernsey, you must apply the 
appropriate location and quality differential to Guernsey. In the case 
of much of the crude oil produced from Federal leases in California, 
MMS anticipates that the market center would be Line 63 (for crude oil 
of like-quality to the crude oil for which Line 63 spot prices are 
published) or Kern River (for crude oil of like-quality to the crude 
oil for which Kern River spot prices are published).
    More specifically, if the NYMEX price (unadjusted by the roll) is 
$29.00 and you do not have an arm's-length exchange agreement between 
Cushing and anywhere in Wyoming from which you could calculate a 
location and quality differential for your sweet crude, you would use 
the Guernsey WTI differential to value your sweet crude oil if you 
transport or exchange some or all of your oil to Guernsey. If the 
Guernsey WTI differential, calculated by taking the average of the 
daily high and lows and then averaged over the published days of the 
month, was -$.50/bbl, the value at Guernsey would be $29.00 - $.50 = 
$28.50/bbl. From this value, you could then subtract your 
transportation costs (or you would adjust for location and quality) 
from the lease to Guernsey.
    If you did not move or exchange any of your oil to Guernsey, you 
would have to propose an alternative location and quality differential 
(between the lease and Guernsey) to MMS. You would then apply the WTI 
differential at Guernsey to adjust to Cushing. MMS is proposing that 
you may use the differential from the lease to Guernsey that you 
propose until MMS prescribes a different differential. If MMS 
prescribes a different differential, you would have to apply MMS' 
differential to all periods for which you used your proposed 
differential. You would have to pay any additional royalties resulting 
from using MMS' differential, plus late payment interest from the 
original royalty due date, or you would report a credit for any 
overpaid royalties plus interest under 30 U.S.C. 1721(h).
    MMS also requests comments regarding alternative valuation 
procedures, including differentials, in valuing sour crude oil in light 
of the fact that the WTI price at Cushing is for light

[[Page 50092]]

sweet crude oil. For example, would it be useful to begin 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? Because Hardisty is farther from 
Rocky Mountain market and refineries, MMS proposed that applicable 
transportation costs would be added to, rather than subtracted from, 
this market center's prices. MMS would like to better understand the 
number of companies for whom Hardisty would be an appropriate market 
center. Would it be better in such cases for the lessee to consult 
directly with MMS on the proper valuation procedure rather than MMS 
providing specifics in the rule?

C. What Adjustments and Transportation Allowances Apply When Valuing 
Production Using Index Pricing?--Sec.  206.112

    MMS is proposing to revise the framework of how and when to apply 
location and quality differentials and transportation allowances in 
calculating royalty value. The current rules are based on the 
proposition that the value of oil not sold at arm's length can be 
accurately measured by known, accepted index prices at market centers. 
In order to accommodate certain transactions where the oil does not 
flow to a market center, the current rule allows lessees, in certain 
circumstances, to value the oil as if its value were the same at some 
alternative location (such as a refinery) as it would be at a market 
center. For example, the regulation currently provides that ``if you 
transport lease production directly to * * * an alternate disposal 
point, you may adjust the index price for your actual transportation 
costs.'' 30 CFR Sec.  206.112(c). However, value at a refinery may not 
be the same as the value at a market center.
    To be sure that all royalty values are properly adjusted by market-
based location and quality differentials (and transportation costs) to 
the NYMEX pricing point (Cushing), MMS is proposing to rewrite section 
206.112. Proposed section 206.112 would clarify that if royalty value 
at the lease is calculated by starting with the NYMEX price, the NYMEX 
price would then be adjusted by applicable transportation costs or 
location and quality differentials between the lease and the market 
center, and then between the market center and Cushing.
    Paragraph (a) of proposed section 206.112 would apply to that 
portion of the oil produced from your lease that is transported or 
exchanged (or both transported and exchanged) between the lease and the 
market center. Paragraphs (b) and (c) would apply to the remainder of 
your oil. Under paragraph (a), if you transport your oil over any 
segment (i.e., between any two points) between the lease and the market 
center, you would determine a transportation allowance under either 
section 206.110 or 206.111. If you exchange your oil for any segment 
between the lease and the market center, you would use location and 
quality differentials derived from your arm's-length exchange 
agreements. (If an exchange agreement is not at arm's-length, you would 
have to obtain MMS approval for a location and quality adjustment. 
Until MMS approves a proposed location and quality differential, you 
would use the location and quality differential derived from your non-
arm's-length exchange agreement. If MMS prescribes a different 
differential, you would have to adjust previously reported and paid 
royalties, together with appropriate interest payments or credits. If 
you do not have an arm's-length exchange agreement for your oil between 
the market center and Cushing, you would use the WTI differential to 
adjust for location and quality between the market center and Cushing. 
You could not both take a transportation allowance and apply a location 
and quality differential between the same two points.
    For example, a lessee produces sour crude from a lease in the Gulf 
of Mexico that trades as Eugene Island (EI) crude. Assume that the 
lessee transports 35 percent of the oil produced from the lease to the 
market center at Houma, Louisiana. To determine the value of that 35 
percent of the production, the lessee first would determine its 
transportation allowance from the lease to Houma under section 206.110 
or 206.111, as applicable. In the alternative, if the lessee has an 
arm's-length exchange agreement between the lease and Houma, it would 
use the location and quality differential derived from that exchange 
agreement for the change in location covered by the exchange agreement. 
The lessee would adjust the NYMEX price by the transportation costs or 
the location and quality differential. If the lessee exchanges the oil 
under an arm's-length exchange agreement between Houma and Cushing, it 
would further adjust the NYMEX price by the location and quality 
differential derived from that agreement. Alternatively, if the lessee 
did not exchange the oil between Houma and Cushing at arm's length, the 
lessee would adjust the NYMEX price by the published WTI-EI 
differential.
    Paragraph (a) also addresses the situation in which the lessee both 
transports and exchanges a particular volume of oil from the lease to a 
market center. Therefore, assume the lessee transports 35 percent of 
the oil produced from the lease to Caillou Island and then exchanges 
that oil with another party at arm's length for Light Louisiana Sweet 
(LLS) at St. James, Louisiana, which is the LLS market center. To get 
the royalty value at Caillou Island, the lessee must add the 
differential in the exchange agreement (assume - $1.00) to the market 
value of LLS, which is the NYMEX price plus the WTI-LLS differential 
(assume - $.50). Assuming a NYMEX price of $29.00, the value at Caillou 
Island would be $27.50. The lessee may then subtract its transportation 
costs from the lease to Caillou Island (assume $1.00) to determine the 
royalty value at the lease (a net value of $26.50).
    In the case of much of the crude oil produced from Federal leases 
in California, MMS anticipates that the market center would be Line 63 
(for crude oil of like-quality to the crude oil for which Line 63 spot 
prices are published) or Kern River (for crude oil of like-quality to 
the crude oil for which Kern River spot prices are published). 
Therefore, to determine the adjusted NYMEX price for oil transported or 
exchanged to either of these market centers, the lessee would adjust 
the NYMEX price for the WTI differential between Cushing and the 
applicable market center.
    Paragraph (b) or (c) of proposed section 206.112 applies when some, 
but not all of a lessee's oil is exchanged or transported to or through 
a market center. Paragraph (b) applies if the lessee transports or 
exchanges (or both transports and exchanges) at least 20 percent of the 
oil produced from the lease to a market center. In that event, the 
lessee would value that portion of the oil not transported or exchanged 
to a market center by the volume-weighted average of the values of the 
oil valued under paragraph (a). Therefore, in the preceding example, 
the lessee transported and exchanged 35 percent of its oil from the 
lease to the market center at St. James. The value of that oil 
calculated in that example was $26.50/bbl. Assume that the lessee also 
transported another 45 percent of its oil from the lease to St. James, 
and that the adjusted NYMEX-based value of that oil was $27.00/bbl. 
Finally, assume that the lessee transported the remaining 20

[[Page 50093]]

percent of the oil to its refinery in New Jersey. Under the current 
regulation, the lessee must come to MMS for advice as to how to value 
the portion of the oil transported to New Jersey. Under the proposed 
rule, to determine the value of that 20 percent, the lessee would 
calculate the volume-weighted average of the other two dispositions. In 
this example, the volume-weighted average = ((.35 x 26.50) + (.45 x 
27.00))/.8 = $26.78. The value of the 20 percent transported to the 
lessee's refinery would be $26.78.
    MMS seeks comments on this proposal as well as comments on whether 
20 percent is a sufficient volume on which to base the value of oil 
that the lessee could not otherwise value under the current rule. MMS 
selected the 20 percent figure for this proposal because it is greater 
than the royalty percentage under the typical offshore lease (16\2/3\ 
percent).
    Paragraph (c) of proposed section 206.112 addresses the situation 
where the lessee does not transport or exchange at least 20 percent of 
the oil to a market center. The lessee would use paragraph (a) to value 
the less than 20 percent portion (if any) that the lessee transports or 
exchanges (or both transports and exchanges) to a market center. For 
the remainder of its lease production, the lessee must come to MMS with 
a proposal for a location and quality differential between the lease 
and the market center. If MMS approves a different differential, the 
lessee would have to adjust its previously reported and paid royalties, 
together with an interest payment or credit. The lessee would use the 
WTI differential to adjust between the market center and Cushing.
    Finally, the current rule is not clear about all situations in 
which a quality differential would be appropriate. For example, a 
lessee could transport its oil from the lease to its refinery at a 
market center, but its oil may be of a higher gravity and a lower 
sulfur content than the crude for which a price is published at the 
market center. In this situation, the lessee should make an adjustment 
for quality even though it has no exchange agreement or quality bank to 
use to make the adjustment. MMS proposes that in such circumstances, a 
lessee would use appropriate posted price gravity tables to adjust the 
value of its 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 it has 
neither exchange agreements nor quality banks to fully adjust the 
quality of its oil to that of the crude oil at the market center. MMS 
has based this factor on its understanding of common sulfur bank 
adjustments for California. For instance, MMS understands, from its RIK 
program, that the All America Pipeline uses a sulfur adjustment of 50 
cents per percent, after the first percent difference in sulfur. MMS 
believes that the typical sulfur content of oil produced from Federal 
leases is in the one to three percent range. Therefore, MMS' use of 2.5 
cents per 0.1 percent sulfur difference would be similar to the factor 
used by the All America Pipeline. MMS believes that the ability to use 
a sulfur quality adjustment is a concern in California, but is seeking 
comments on whether producers in other parts of the country would find 
it useful as well. MMS also seeks comments on whether these are 
reasonable differentials, both for California and the rest of the 
country.

D. 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 is proposing to amend 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. In 
1988, MMS determined that the appropriate rate of return was equal to 
the Standard and Poor's BBB bond rate. MMS explained its choice as 
follows:

    The MMS has examined several options relating to rate of return 
and decided that a rate of return should be closely associated with 
the cost of money necessary to construct transportation facilities. 
The MMS has examined the use of the corporate bond rate very 
carefully and has concluded that such rates are representative of 
the loan rates on sums of money comparable to that expected for the 
construction of transportation facilities.
    There is no doubt that there are some very high risks involved 
with some oil and gas ventures, such as wildcat drilling. However, 
the risk associated with building and developing a pipeline to move 
oil that has already been discovered is a much different risk. The 
risk of default (financial risk) is considered in corporate bond 
rates. Considering the risks related to transportation systems, a 
rate of return based on an applicable corporate bond rate would be 
appropriate for transportation systems.
53 FR 1213 (1988)
    In 2000, when MMS revised the oil valuation regulations, MMS 
explained why it would continue to use the Standard and Poor's BBB bond 
rate as the rate of return for transportation allowances:

    The fact that a lessee's overall operations are funded 
historically by some proportion of debt and equity does not imply 
that the resulting aggregate weighted average cost is appropriate 
for determining a proper transportation allowance for royalty 
purposes. * * * MMS's research indicates that most recent pipeline 
investments are financed largely through debt rather than equity. 
For those pipelines financed entirely by debt, the BBB bond rate is 
a very favorable rate * * *
    The industry proposes using a weighted average cost of capital. 
* * * [W]e agree with industry's proposal to calculate a before-tax 
rate of return. Royalties are calculated before tax, so the rate of 
return used should be before-tax rate as well. * * * Even if, 
arguendo, we accepted the premise of using a weighted average cost 
of capital as the rate of return, MMS has found, using more 
appropriate SIC codes, tax rates, debt rates, and equity rates, that 
the average cost of capital is much lower than the 2.2 times BBB 
that industry calculated. MMS therefore concluded that industry's 
proposal is not well founded. * * * [S]ince the BBB bond rate is 
adequate as a rate of return used in calculating actual 
transportation costs for royalty purposes, there is no need for MMS 
to utilize the expertise of FERC staff to develop costs of debt and 
equity.

65 FR 14051
    MMS believes that a market-based cost of capital is needed to 
reflect accurately the actual and necessary costs to owners of 
transportation systems. The capital costs, in addition to operating and 
maintenance expenses, must be accounted for in calculating costs. 
Capital costs are normally accounted for by allowing depreciation plus 
a rate of return on undepreciated capital investment.
    Industry has challenged the 2000 rule as allegedly arbitrary and 
capricious in the lawsuit cited earlier. Among the challenged aspects 
of that rule is whether the Standard and Poor's BBB corporate bond rate 
is sufficient as an average rate of return on transportation capital 
investments. The 2000 rule also eliminated the exception allowing 
lessees to use tariffs filed with FERC as a transportation allowance in 
lieu of calculating actual transportation costs. Consequently, after 
June 1, 2000, calculation of actual costs, and the use of the rate of 
return as part of the calculation, was required of all lessees who did 
not have arm's-length transportation arrangements. The judicial 
challenge to the 2000 rule has led MMS to reconsider whether BBB is a 
sufficient rate of return.
    When MMS promulgated regulations to value geothermal resources in 
1992, MMS believed that the return on capital needed to compute 
properly a deduction for the costs of generating electricity should be 
the weighted

[[Page 50094]]

average of the returns to equity and debt (without considering income 
tax treatment). That led MMS to determine that two times the BBB rate 
was appropriate for that calculation.
    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. MMS believes 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 believes that the subset of companies that have invested, or 
are likely to invest, in oil pipelines is a very limited subset of the 
oil industry. MMS also believes that no standard industrial 
classification corresponds to those who are willing to invest in 
pipelines. MMS has received a new study from the American Petroleum 
Institute (``API''), titled ``BBB Bond Rate Not an Adequate Measure of 
Capital Cost,'' that concluded that the cost of capital (after taxes) 
of the Department of Energy's Financial Reporting Service Companies was 
closer to 1.6 to 1.8 times the Standard and Poor's BBB bond rate. The 
API study explained that this group of producers included the companies 
that would be most likely to own pipelines. MMS, through its Offshore 
Minerals Management, Economics Division, has also 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. This 
study concluded that that range of rates of return that would be 
appropriate for oil pipelines would be in the range of 1.1 to 1.5 times 
the Standard and Poor's BBB bond rate. While the relationship between 
the rates of return that MMS has examined and the BBB rate has not been 
constant, MMS is proposing for comment a rate of return of 1.5 times 
the Standard and Poor's BBB rate as this rate is within the range 
recommended by its own experts and close to the rate recommended by the 
industry experts.
2. Specification of Certain Allowable and Non-Allowable Costs--
Sec. Sec.  206.110 and 206.111
(i) Arm's-Length Transportation
    In Section 206.110, MMS is proposing to add a new paragraph (b) 
that would specify many of the costs incurred for transporting oil 
under an arm's-length contract that are allowable deductions. MMS 
believes these costs are costs that are directly related to the 
movement of crude oil to markets away from the lease. Those costs 
include:
    (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 to a pipeline owner 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 the shipper to 
maintain in the pipeline by the value of that volume for the current 
month calculated under section 206.102 or section 206.103, as 
applicable; and (ii) multiply the value calculated under paragraph (i) 
by the monthly rate of return, calculated by dividing the rate of 
return specified in section 206.111(i)(2) by 12.
    MMS proposes to allow this deduction because this cost appears to 
be an actual cost directly associated with transporting oil. In each 
month for which line fill is required, a shipper incurs the loss of 
available capital associated with the value of the line fill volume. 
The proposal therefore would allow a return on that value, calculated 
as described above. MMS seeks comments on whether this cost should be 
allowed as part of the transportation deduction.
    (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.
    MMS proposes to allow lessees to deduct transfer fees paid to a hub 
operator associated with physical movement of crude oil through the hub 
when the shipper does not sell the oil at the hub. MMS believes that 
this also is a cost directly incurred for movement of the oil. MMS 
believes that title transfer fees are a cost of selling oil, not moving 
it, and are not deductible.
    (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. While this situation 
does not arise frequently, MMS believes that in such cases, this 
volumetric deduction is an actual cost incurred in moving oil.
    (10) Costs of securing a letter of credit or other surety that the 
pipeline requires a shipper to maintain. These costs should only 
include the currently allocable costs applicable to the Federal lease. 
MMS believes that shippers can 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 they receive their 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.
    In the first case, if you make a cash deposit of two 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:
    (i) Multiply the deposit by the monthly rate of return, calculated 
by dividing the rate of return specified in section 206.111(i)(2) by 
12, and (ii) multiply that result by the proportion of total production 
from each Federal lease. In this example, if the Standard and Poor's 
BBB bond rate was 8%, the allowable monthly rate would be
[GRAPHIC] [TIFF OMITTED] TP20AU03.020

and that would be multiplied by the amount of the deposit to get the 
monthly cost, which would be $500. Then you could include the share of 
that applicable to the Federal lease (75,000/100,000) = \3/4\. So you 
could include $375 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 believes that this is a cost that the lessee must incur to 
obtain the

[[Page 50095]]

pipeline's transportation service, and therefore is a cost of moving 
the oil. MMS welcomes comments on whether these are reasonable ways to 
calculate the actual costs of assuring a lessee's creditworthiness.
    You may not use any cost as a deduction that duplicates all or part 
of any other cost that you use under this paragraph. MMS seeks comments 
regarding whether these various costs should be allowed, and whether 
there are other costs directly attributable to the transportation of 
crude oil that should be included in the final rule.
    In section 206.110, MMS proposes a new paragraph (c) that would 
specify certain costs as not deductible. Those include:
    (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 scheduling service providers.
    (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.
    At the workshops, MMS received some comments that internal costs 
should be deductible. One person suggested that if an employee's only 
function were to arrange for downstream transportation of production, 
that person's salary should be deductible. MMS does not agree. Under 
the proposed rule, these types of indirect, internal costs are not 
deductible.
    MMS does not believe that any of the above-described costs are 
incurred directly as part of the process of physically moving the crude 
oil. MMS seeks comments on whether any of these costs should be 
deductible.
(ii) Non-Arm's-Length Transportation
    In section 206.111, MMS proposes to add a new paragraph (b)(6) 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. Many of 
these costs are the same as those associated with arm's-length 
transportation contracts. Those costs include:
    (1) Volumetric adjustments for actual line losses.
    (2) 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:

(A) Multiply the volume that the pipeline requires the shipper to 
maintain, and that it does maintain, in the pipeline by the value of 
that volume for the current month calculated under section 206.102 or 
section 206.103, as applicable; and (B) multiply the value calculated 
under paragraph (i) by the monthly rate of return, calculated by 
dividing the rate of return specified in section 206.111(i)(2) by 12.

    (3) 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.
    (4) 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.
    (5) 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 costs parallel those costs itemized in the arm's-length 
transportation provisions in section 206.110(b) insofar as appropriate 
for non-arm's-length situations. Several of the specific items allowed 
under the arm's-length provisions do not occur or are not appropriate 
for inclusion in a non-arm's-length transportation situation. 
Specifically, in a non-arm's-length situation, there is no arm's-length 
transportation tariff. (Instead, the lessee must calculate its actual 
costs of building and operating the pipeline.) In addition, MMS 
believes that even if an affiliated pipeline charges quality bank 
administrative fees to its own affiliate, the lessee/shipper is simply 
paying its affiliate and that it should not be regarded as part of the 
actual costs incurred to move oil. Further, in a non-arm's-length 
situation, decisions regarding short-term storage (and the cost 
associated with that storage) are under the lessee's or its affiliate's 
control, and likely may be avoided. MMS therefore believes that it is 
not appropriate to allow a short-term storage cost. Also, in a non-
arm's-length situation, any fees charged by an affiliated pipeline to 
pump oil over to a third party-carrier's system are paid within the 
same corporate organization and are not an additional actual cost of 
transportation. Finally, in non-arm's-length situations, MMS expects 
that requiring a letter of credit from an affiliated producer is 
unnecessary and that the corporate organization ordinarily would avoid 
incurring the costs of the premium necessary for the letter of credit. 
MMS therefore believes it inappropriate to allow such a deduction.
    In contrast to the 2000 rule, which disallows all line losses in 
non-arm's-length transportation situations, MMS proposes to allow 
actual, but not theoretical, line losses. MMS believes that actual line 
losses properly may be regarded as a cost of moving oil. In addition, 
if there is a line gain, the lessee must reduce its transportation 
allowance accordingly. In a non-arm's-length situation, however, a 
charge for theoretical line losses would be artificial and would not be 
an actual cost to the lessee. While a lessee may have to pay an amount 
to a pipeline operator for theoretical line losses as part of an arm's-
length tariff, in a non-arm's-length situation, line losses, like other 
costs, should be limited to actual costs incurred.
    The MMS also is proposing to add a new paragraph (b)(7) to section 
206.111 that would list the costs that expressly are not deductible as 
transportation costs. These are the same costs discussed above in the 
section on arm's-length transportation contracts (section 206.110), 
with one addition, namely, that theoretical line losses are not 
deductible under non-arm's-length transportation arrangements.
3. Technical Correction to Sec.  206.111(h)(5) Regarding Redepreciation
    We propose to modify existing Sec.  206.111(h)(5) to remedy an 
unintended consequence regarding depreciation when calculating a 
transportation allowance not involving an arm's-length transportation 
contract. 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

[[Page 50096]]

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' 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 proposes to modify 
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 would 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.

E. Treatment of Joint Operating Agreements--Sec.  206.102

    In the preamble to the 2000 rule, MMS explained:

    If a lessee sells to a co-lessee/designee under a joint 
operating agreement, MMS ordinarily will regard that arrangement as 
the designee disposing of production on the lessee's behalf and not 
as an actual sale to the designee.

65 FR 14060
    Based upon further consideration of these situations, MMS does not 
believe there should be a presumption that all of these sorts of 
transactions are non-arm's-length and are not sales. When a party to a 
joint operating agreement, who is not the operator, allows the operator 
to dispose of its 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. The royalty value 
of the oil so transferred depends on whether the sale is an arm's-
length sale. MMS expects that in most of the situations where the 
lessee is not the operator, the transaction may be at arm's-length. If 
the sale is at arm's-length, the question then becomes (as in any 
arm's-length situation) whether any of the exceptions in section 
206.102(c) apply. In some circumstances, the sale also may be a 
marketing agreement, and the operator may be performing the marketing 
function for the lessee. In such a case, the MMS may determine that the 
lessee has improperly deducted marketing costs, and MMS may increase 
the royalty value accordingly. MMS will examine each case on its facts 
just as it does any other disposition of production.
    MMS also proposes to change the reporting instructions in 30 CFR 
210.53 with respect to sales under joint operating agreements to 
facilitate review and audit of these transactions. MMS proposes to add 
a new paragraph (c) to section 210.53 that would require an operator 
under a joint operating agreement who is also a designee and who 
reports and pays royalty on behalf of one or more working interest 
owners from whom the operator buys production, to report the share of 
the production it purchased from the working interest owners and the 
associated royalty payment on a separate line on the Form MMS-2014 from 
the line on which the operator reports its own share of production and 
the associated royalty payment.

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

    The MMS is proposing a technical correction to the regulation at 
section 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 are proposing to end-
date the grace period for such adjustments, because we consider three 
years to be sufficient time to have reported and paid royalties under 
the regulations published in 2000.

G. Other Technical Changes

    Section 206.103(b) applies to production from leases in the Rocky 
Mountain Region, a defined term. The current rule prescribes a series 
of four benchmarks described in paragraphs (b)(2) through (b)(5) for 
valuing production in the Rocky Mountain Region that is not sold at 
arm's-length. To provide clarity in this section of the rule, MMS is 
proposing to renumber paragraphs (b)(2) through (b)(5) to make them 
(b)(1) through (b)(4) so that the four benchmarks correspond with the 
four paragraph numbers. Other than this renumbering, the only change 
MMS is proposing to make to the valuation criteria for the Rocky 
Mountain Region is the change to the third benchmark from spot prices 
to NYMEX valuation, described above in I. A.
    In addition, MMS proposes a technical change to the definition of 
``affiliate'' in section 206.101. MMS would change paragraph (2) of the 
definition of ``affiliate'' by striking the words ``of between 10 and 
50 percent'' and substituting therefor 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.

H. Other Possible Changes That May Be Considered

    In addition to issues already identified above on which MMS seeks 
comments, MMS specifically requests comments on the following issue: 
Should MMS allow using 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?
    Under the 2000 rule, most lessees who are relatively large 
producers have the option of using a spot market index-based value even 
when the oil is sold at arm's length, because the lessee is working 
through an affiliate who is the seller in an arm's-length resale. Thus, 
if a lessee wants to avoid the burden of ``tracing'' the production to 
each particular sale out of a large number of sales to different 
purchasers, it may opt to use index-based value under the current 30 
CFR Sec.  206.102(d)(2). Lessees who do not first transfer to an 
affiliate and who sell directly to a large number of different 
purchasers do not have this option. MMS seeks comment on whether the 
option of using NYMEX prices should be extended to these situations in 
the event that MMS adopts NYMEX-based valuation.

II. Procedural Matters

1. Public Comment Policy

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

[[Page 50097]]

2. Summary Cost and Royalty Impact Data

    Summarized below are the estimated costs and royalty impacts of the 
proposed rule to all potentially affected groups: Industry, the Federal 
Government, and State and local governments. The costs and the royalty 
collection impacts, are segregated into two categories--those that 
would accrue in the first year after the proposed rule becomes 
effective and those that would accrue on a continuing basis each year 
thereafter.

A. Industry

(1) Expected Increase in Royalties--NYMEX-Based Valuation Applied to 
Oil Not Sold at Arm's Length

    Under this proposed rule, industry would 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 current regulations. We provide estimates below of any 
significant increased royalties under the proposed rule.
    The proposed rule maintains many of the provisions of the Federal 
oil valuation rule that became effective June 1, 2000 (the June 2000 
Rule), including the concept of three separate valuation methodologies 
linked to different production locations. This analysis also is divided 
into the same three areas. They include California/Alaska (onshore and 
offshore), the Rocky Mountain Region, and the ``rest of the country'' 
including the Gulf of Mexico. 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 would change somewhat, and some additional corresponding 
analysis is necessary.
``Rest of the Country''
    In valuing production not sold under an arm's-length contract, the 
June 2000 Rule employed the spot price of the oil most closely 
associated with the production, with appropriate adjustments for 
location and quality. The timing of the spot month that corresponds 
with the production month is 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 is valued using the spot quotes 
for the oil most similar in location and quality from November 26th 
through December 25th.
    The proposed 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 differential. 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, during the production month for 
deliveries during the prompt month as defined in the proposed 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 would 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 taking a ratio of the difference between the 
current month value, the 2nd month out future value, and the 3rd month 
out future value as reported on the NYMEX exchange. Assuming the 
``roll'' calculation results in a value of $0.30 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 have compared prices under NYMEX adjusted for the roll and the 
grade differential discussed above with prices calculated under the 
existing rule based on spot prices at each of the market centers 
applicable in the ``rest of the country--e.g., Midland, St. James, and 
Empire. We found that over the period April 2000 through December 2002, 
or the period from approximately when the current rule became effective 
through the end of calendar year 2002, the adjusted average monthly 
NYMEX price exceeded the monthly average spot prices for these market 
centers by about $0.31 per barrel. We also have 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 $0.31 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 $0.31 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 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 former includes only barrels currently taken in the small refiner 
program, and the latter includes small refiner volumes plus barrels 
currently going to the Strategic Petroleum Reserve. We then subtracted 
the volumes taken in kind and applied the $0.31 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 million per year.
California/Alaska
    The current rule specifies Alaska North Slope (ANS) spot prices for 
oil delivered at Long Beach, California as the valuation basis for all 
crude produced in California or Alaska and not sold at arm's length. 
The ANS spot quotes on a monthly average basis (without weekends or 
holidays) apply directly to the production month. That is, the spot 
quotes from December 1st through the 31st apply directly to December 
production. The rule allows for transportation adjustments and quality 
allowances.
    The proposed new methodology is the NYMEX Calendar Month Average 
daily settlement price with appropriate differentials, but without the 
``roll'' discussed above. This method uses a trade-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 the proposed rule.
    For example, for the month of December, assume a producer seeks to 
value production whose quality and location are similar to Kern River 
crude oil (13.4 degree API gravity oil in Kern County). The grade 
differential

[[Page 50098]]

established over the period October 26 through November 25 would 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 Kern 
River spot price for the same period. Assuming the WTI value is $29.00 
per barrel and the Kern River value is $20.00 per barrel, the negative 
$9.00 per barrel differential would be added to the NYMEX calendar 
month average price corresponding to the month of production (without 
weekends or holidays). Using the same NYMEX value, $29.50 per barrel, 
as in the previous example, the royalty value calculation would be as 
follows:

(Trading month CA spot oil assessment-Spot WTI assessment) + NYMEX 
calendar month average ($20-$29) + $29.50 = $20.50 applied to all 
December royalty volumes that are valued as not sold under an arm's-
length contract.

    Because the proposed new valuation method uses new oil types and 
locations as its basis, location and quality adjustments must be made 
to the current basis (ANS) to make a meaningful comparison of values 
calculated under the proposed and current rules. Estimating the proper 
adjustments with precision is very difficult.
    For example, again using Kern River crude oil to compare to ANS, 
there are significant differences in quality (13.4 degrees for Kern 
River and 29.5 for ANS) and in location (Kern County, CA and Long 
Beach, CA). The sulfur content of the two oils is nearly identical, so 
no sulfur price adjustment is needed. Gravity differential estimates 
can vary significantly because California posted price adjustment 
scales vary from $0.15 per degree API gravity to $0.25 per degree or 
more. The gravity adjustment range would then be from $2.42 to $4.03 
per barrel.
    The location differential can be estimated by the use of a tariff 
between points in Kern County to Long Beach. These tariffs currently 
range between $.75 and $1.25 per barrel.
    Depending on how these differentials apply in specific cases, the 
result could be deductions from the ANS price from $3.17 to $5.28 per 
barrel in order to compare the adjusted ANS price to value calculated 
under the proposed rule. The result could be an overall royalty 
increase or decrease. Applying the high gravity and location 
adjustments above to the ANS price from 1999 through 2002 would result 
in an adjusted ANS price about $1.00 per barrel lower than the price 
derived under the proposed rule. Applying the low gravity and location 
adjustments to the ANS price would result in a value about $1.00 above 
the price derived under the proposed rule.
    In estimating the impact of a change to NYMEX valuation, we made 
several assumptions in addition to the $1.00 per barrel increase or 
decrease. For California 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 onshore royalty rate is one-
eighth, and that volumes taken in kind in the small refiner program are 
10,000 barrels per day. We then subtracted the volumes taken in kind 
and applied the $1.00 per barrel figure to the remaining barrels 
assumed to be valued under the non-arm's-length provisions. We estimate 
a range of -$2,120,650 to +2,120,650 per year in terms of higher or 
lower royalty payments. This range results because the location and 
quality adjustments can vary significantly. For Alaska we based our 
estimate on an average offshore royalty production of 1,600 barrels per 
day, and we assumed that all production would be valued under the non-
arm's-length provisions. Using the same $1.00 per barrel figure that we 
used in California, we estimate a range of -$584,000 to +584,000 per 
year in terms of higher or lower royalty payments.
Rocky Mountain Region
    Determining the impact of any proposed modification of the current 
pricing methodology for valuing oil not sold at arm's-length in the 
Rocky Mountain Region is also 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. 
Although this proposal does involve NYMEX pricing, it would apply only 
if and when the first two benchmark procedures (which rely exclusively 
on arm's-length values) are inapplicable. Where the third benchmark 
applies, valuation of Wyoming Sweet would rely on differentials between 
WTI at Cushing, Oklahoma, and Wyoming Sweet at Guernsey, Wyoming.
    The proposed Wyoming Sweet valuation methodology is identical to 
that for California, with the obvious substitution of the Wyoming Sweet 
spot price for the California grades. 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 have compared prices under NYMEX adjusted for the grade 
differential (and not the ``roll,'' as discussed earlier) with prices 
calculated under the existing rule based on spot prices at Guernsey, 
Wyoming--the only market center in the Rocky Mountain Region. We used 
the same time period, April 2000 through December 2002, as we did for 
the Rest of the Country (see footnote 3). Over this period the monthly 
average spot price exceeded the adjusted average monthly NYMEX price by 
about $0.04 per barrel. We have also performed this comparison back to 
the beginning of 1999 and find that the adjusted NYMEX price exceeded 
the monthly average spot price by about $0.02 per barrel over the 
entire period January 1999 through December 2002. To illustrate the 
highest potential cost to industry, we chose the $0.02 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 $0.02 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 would rely on NYMEX prices, we assumed that 25 percent 
of all Federal barrels that are valued under the benchmarks would be 
valued under each of the benchmarks and hence only 25 percent of those 
barrels would rely on NYMEX prices. (None of the other three benchmarks 
would change.) Thus 12\1/2\ percent of all Federal barrels would 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 $0.02 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 Reduction--

(i) Increase Rate of Return in Non-Arm's-Length Situations From 1 Times 
the Standard and Poor's BBB Bond Rate to 1.5 times the Standard and 
Poor's BBB Bond Rate
    The MMS does not routinely collect detailed allowance information, 
such as affiliation between the payor and transporter or the cost 
components used

[[Page 50099]]

to calculate a non-arm's-length allowance rate. Therefore we had to 
make several broad assumptions in order to estimate the impact of the 
proposed rule. We assumed that 50 percent of all allowances are non-
arms-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 \1/2\ 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 estimated 
that increasing the basis for the rate of return by 50 percent could 
result in additional allowance deductions of $3,780,283 ($7,560,565 x 
.50). Our review of transportation allowances deducted from oil 
royalties in the States of Wyoming, Colorado, Utah, and New Mexico 
revealed minimal amounts deducted from onshore leases. Therefore, we 
assumed that this entire increase would impact offshore royalties only.
(ii) Allow Line Loss as a Component of a Non-Arm's-Length 
Transportation Allowance
    For offshore production, we based this estimate on the total 
offshore oil royalties for FY 2001 of $2,069,450,791. We assumed that 
50 percent of all allowances are non-arms-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 needed to 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 production of 222,100 BOPD, 
the amount of oil transportation subject to these regulations could 
range from a high of 77 percent of the production to a low of 19 
percent of the production. [(222,100 - 50,000) / 222,100 = 77%; 
(222,100-180,000) / 222,100 = 19%]. Applying the high and low range 
factors 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%) to $1,593,477 ($2,069,451 x 77%) per year.
(iii) Allow Quality Bank Administration Fees As a Component of an 
Arm's-Length and a Non-Arm's-Length Transportation Allowance
    For offshore oil production, we based our estimate on the total 
offshore oil royalty volume for FY 2001 of 81,066,567 barrels. We also 
estimated that quality bank administrative fees were $0.002 per barrel. 
We estimated that allowing such fees could result in additional 
offshore transportation allowances of $162,133 (81,066,567 x $0.002) 
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 - 19%) to $124,842 ($162,133 - 77%) 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 $0.002)
(iv) Allow Line Fill As a component of an Arm's-Length and a Non-Arm's-
Length Transportation Allowance
    For offshore oil production, we based this estimate on the total 
offshore oil royalty volume for FY 2001 of 81,066,567 barrels. We 
estimated that line fill costs ranged from $0.02 to $0.05 per barrel. 
We then estimated that this factor could result in additional 
transportation allowances of $1,621,331 (81,066,567 x $0.02) to 
$4,053,328 (81,066,567 x $0.05) 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%) to $3,121,062 
($4,053,328 x 77%) per year. For Onshore production we estimated that 
this factor could result in additional transportation allowances of 
$189,924 (9,496,181 x $0.02) to $474,809 (9,496,181 x $0.05).
Allow the Cost of a Letter of Credit As a Component of an Arm's-Length 
Transportation Allowance
    Again we assumed that 50% of allowances were 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 $0.02 to $0.05 per barrel. We thus estimated that this 
could result in additional transportation allowances of $810,666 
(81,066,567 x $0.02 x .5) to $2,026,664 (81,066,567 x $0.05 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%) to $1,560,531 ($2,026,664 x 77%) 
per year. For Onshore production we estimated that this factor could 
result in additional transportation allowances of $94,962 (9,496,181 x 
$0.02 x.5) to $237,405 (9,496,181 x $0.05 x .5).
(vi) Royalty Reduction Summary, items (i)-(v)--Additional Deductions 
for Allowances
    We estimate that between $4,666,363 and $10,180,195 in additional 
transportation allowances could be deducted from OCS 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 from Onshore Federal lease royalties.

(3) Cost--Administration--

(i) System Modifications To Reflect NYMEX Pricing Basis
    We believe any increases in administrative costs related to changes 
in non-arm's-length valuation procedures would 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 uses the 
non-arm's-length provisions of the current rule already has access to 
the needed publications and exchange agreements. For some lessees, 
modification of computer programs related to royalty

[[Page 50100]]

calculation and payment may be needed. We think that only about 50 of 
the approximately 800 Federal oil royalty payors would 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 would be $250,000.
(ii) Proposal of a Location Differential Under 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 
would have to: (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 their 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 would be 660 hours (2 x 330), including 
record keeping. 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 Increased Royalty Revenues

    States receiving revenues from offshore Outer Continental Shelf 
Lands Act Section 8(g) leases would share in a portion of the estimated 
additional $4,303,913 to $11,658,663 in royalties that would accrue 
annually from the ``rest of the country'' under the proposed valuation 
methodology. Based on each 8(g) State's share of total offshore 
royalties for FY 2001 and their 8(g) disbursement percentage, we 
estimate the States' 8(g) share to be between $26,363 and $71,119. 
Onshore States would receive additional revenue of $317,682.
    The State of California would share in a portion of the estimated 
$2,120,650 increase to $2,120,650 decrease in royalties accruing from 
California. We estimate that royalties accruing to the State of 
California for onshore production would range from an increase of about 
$524,317 to a decrease of about $524,317. We further estimate that its 
8(g) share would range from an increase of about $53,692 to a decrease 
of about $53,692. For Alaska we estimate that its 8(g) share would 
range from an increase of about $157,680 to a decrease of about 
$157,680, with no onshore impact. 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 Decreases--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 $33,785 and $73,705 in additional 
transportation allowances may be deducted from the States' share of 
Federal royalties for OCS 8(g) leases. In addition, we estimate that 
between $278,227 and $491,891 may be deducted from the States' share of 
onshore Federal lease royalties.

C. Federal Government

    Because many of the changes in the proposed 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 would receive an estimated $4,303,913, to 
$11,658,663 in royalties each year from the ``rest of the country,'' of 
which affected States would 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 California 
we estimate the range of royalty impacts to be from a decrease of 
$1,542,630 to an increase of $1,542,630 per year. For Alaska, we 
estimate the range of royalty impacts to be from a decrease of $426,320 
to an increase of $426,320 per year. 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 
from the affected States.

(2) Expected Royalty Decreases--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 $4,632,578 and $10,106,490 per year in 
additional transportation allowances may be deducted from Federal OCS 
royalties and between $278,227 and $491,891 from onshore royalties.

(3) Cost--Proposal of a Location Differential Uunder 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 would 
have to: (1) Respond in writing; (2) verify 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 record keeping. 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 numbers 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 have assumed that the average for royalty increases or 
decreases would be the midpoint of the proposed range.

[[Page 50101]]



                  Summary of Costs and Royalty Impacts
------------------------------------------------------------------------
                                Costs and royalty increases or royalty
                                               decreases
         Description         -------------------------------------------
                                   First year         Subsequent years
------------------------------------------------------------------------
                               A. Industry
------------------------------------------------------------------------
(1) Royalty Increase based    Rocky Mtn Region:     Rocky Mountain
 on using the revised NYMEX    $11,738.              Region: $11,738.
 pricing.                     California: -         California: -
                               $2,120,650 to         $2,120,650 to
                               $2,120,650.           $2,120,650.
                              Alaska: -$584,000 to  Alaska: -$584,000 to
                               $584,000.             $584,000.
                              Rest of Country: -    Rest of Country: -
                               $4,303,913 to         $4,303,913 to
                               $11,658,663.          $11,658,663.
(2) Royalty Decrease--        -$5,222,817 to -      -$5,222,817 to -
 Increased Allowable Costs.    $11,163,977.          $11,163,977.
(3) Net Expected Change in    -$200,371...........  -$200,371.
 Royalty Payments from
 Industry.
(4) Expected Range of         -$9,552,976 to        -$9,552,976 to
 Royalty Impact.               $9,152,234.           $9,152,234.
(5) Administrative Cost--     $283,000............  $33,000.
 reprogramming of systems
 and submitting location
 differential requests.
-----------------------------
                     B. State and Local Governments
------------------------------------------------------------------------
(1) Royalty Increase--        Rocky Mtn. Region:    Rocky Mtn. Region:
 increased royalty revenue     $5,869.               $5,869.
 in terms of the States'      California: -         California: -
 share of Federal royalties.   $578,009 to           $578,009 to
                               $578,009.             $578,009.
                              Alaska: -$157,680 to  Alaska: -$157,680 to
                               $157,680.             $157,680.
                              Rest of Country:      Rest of Country:
                               $344,045 to           $344,045 to
                               $388,801.             $388,801.
(2) Royalty Decrease--        8(g) States: -        8(g) States: -
 Increased Allowable Costs     $33,785 to -$73,705.  $33,785 to -
 in terms of the States'      All Other States: -    $73,705.
 share of Federal royalties.   $278,227 to -        All Other States: -
                               $491,891.             $278,227 to -
                                                     $491,891.
(3) Net Expected Change to    -$66,512............  -$66,512.
 Royalty Payments to States.
(4) Expected Range of         -$951,371 to          -$951,371 to
 Royalty Impact.               $818,347.             $818,347.
-----------------------------
                          C. Federal Government
------------------------------------------------------------------------
(1) Royalty Increase--        Rocky Mtn Region:     Rocky Mtn Region:
 increased royalty revenues    $5,869.               $5,869.
 net of the States' share.    California: -         California: -
                               $1,542,630 to         $1,542,630 to
                               $1,542,630.           $1,542,630.
                              Alaska: -$426,320 to  Alaska: -$426,320 to
                               $426,320.             $426,320.
                              Rest of Country:      Rest of Country:
                               $3,959,868 to         $3,959,868 to
                               $11,269,862.          $11,269,862.
(2) Royalty Decrease--        -$4,910,805 to -      -$4,910,805 to -
 Increased Allowable Costs     $10,598,381.          $10,598,381.
 net of the States' share.
(3) Net Expected Change in    -$133,859...........  -$133,859.
 Royalty Payment to the
 Federal Government.
(4) Expected Range of         -$8,601,605 to        -$8,601,605 to
 Royalty Impacts.              $8,333,887.           $8,333,887.
(5) Cost of administrating    $33,000.............  $33,000.
 location differential
 requests.
------------------------------------------------------------------------

3. Regulatory Planning and Review, Executive Order 12866

    In accordance with the criteria in Executive Order 12866, this 
proposed rule is not an economically significant regulatory action as 
it does not exceed the $100 million threshold. The Office of Management 
and Budget (OMB) has made the determination under Executive Order 12866 
to review this proposed rule because it raises novel legal or policy 
issues.
    1. This proposed rule will not have an annual effect of $100 
million or adversely affect an economic sector, productivity, jobs, the 
environment, or other units of Government. MMS has evaluated the costs 
of this rule, and estimates that industry would 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 would incur $33,000 each year 
in additional administrative costs.
    2. This proposed rule will not create inconsistencies with other 
agencies' actions.
    3. This proposed rule will not materially affect entitlements, 
grants, user fees, loan programs, or the rights and obligations of 
their recipients.
    4. This proposed rule will raise novel legal or policy issues. See 
proposed modifications in the Provisions of This Proposed Rule in the 
attached Threshold Analysis.

4. Regulatory Flexibility Act

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

[[Page 50102]]

retaliation by an MMS employee may include suspension or termination 
from employment with the Department of the Interior.

5. Small Business Regulatory Enforcement Act (SBREFA)

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

6. Unfunded Mandates Reform Act

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

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

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

8. Federalism, Executive Order 13132

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

9. Civil Justice Reform, Executive Order 12988

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

10. Paperwork Reduction Act of 1995

    This proposed rule contains new information collection requirements 
that we have submitted to the Office of Management and Budget (OMB) for 
review and approval under section 3507(d) of the Paperwork Reduction 
Act of 1995. As part of our continuing effort to reduce paperwork and 
respondent burden, we invite the public and other Federal agencies to 
comment on any aspect of the reporting burden.
    Submit your comments by fax (202) 395-6566 or e-mail ([email protected]) to the Office of Information and Regulatory 
Affairs, OMB, Attention Desk Officer for the Department of the Interior 
(OMB Control Number 1010-NEW).
    Send copies of your comments to Sharron L. Gebhardt, Regulatory 
Specialist, Records and Information Management Team, Minerals 
Management Service, Minerals Revenue Management, P.O. 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. You may also e-mail your comments to us 
at [email protected]. Include the title of the information 
collection and the OMB Control number in the ``Attention'' line of your 
comment. Also include your name and return address. Submit electronic 
comments as an ASCII file avoiding the use of special characters and 
any form of encryption. If you do not receive a confirmation that we 
have received your e-mail, contact Ms. Gebhardt at (303) 231-3211.
    OMB has up to 60 days to approve or disapprove this collection of 
information but may respond after 30 days. Therefore, public comments 
should be submitted to OMB within 30 days in order to assure their 
maximum consideration. However, we will consider all comments received 
during the comment period for this notice of proposed rulemaking.
Information Collection Burden
    The annual reporting burden is 1608 hours. We expect approximately 
40 responses from 7 Federal lessees to submit the required information. 
The burden estimates include the time for reviewing instructions, 
searching existing data sources, gathering and maintaining the data 
needed, and completing and reviewing the collection of information. 
Using an average cost of $50 per hour, the total cost to respondents is 
$80,400.

----------------------------------------------------------------------------------------------------------------
                                                                                                        Annual
    Proposed 30 CFR part 206         Reporting and recordkeeping      Burden hours    Annual number     burden
           subpart C                        requirements              per responses   of responses      hours
----------------------------------------------------------------------------------------------------------------
206.103(b)(4)..................  If you demonstrate to MMS's                    330               1          330
                                  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.
206.112(a)(2)(ii)..............  For oil that you exchange between              330               1          330
                                  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.
206.112(c)(1)..................  If you transport or exchange (or               330               2          660
                                  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 a
                                  differential between the lease
                                  and the market center for the
                                  portion of the oil that you do
                                  not transport or exchange * * *.

[[Page 50103]]

 
210.53(c)(1) and (2)...........  On the Form MMS-2014, the operator               8              36          288
                                  must report the following
                                  information on separate lines:
                                  (1) The share of the production
                                  the operator purchased from each
                                  working interest owner and the
                                  associated royalty payment; and
                                  (2) The operator's own share of
                                  production and the associated
                                  royalty payment.
                                                                    -----------------
----------------------------------------------------------------------------------------------------------------

    Public Comment Policy. The PRA (44 U.S.C. 3501, et seq.) provides 
that 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. Before submitting an ICR to OMB, 
PRA Section 3506(c)(2)(A) requires each agency ``* * * to provide 
notice * * * and otherwise consult with members of the public and 
affected agencies concerning each proposed collection of information * 
* *.'' Agencies must specifically solicit comments to: (a) Evaluate 
whether the proposed collection of information is necessary for the 
agency to perform its duties, including whether the information is 
useful; (b) evaluate the accuracy of the agency's estimate of the 
burden of the proposed collection of information; (c) enhance the 
quality, usefulness, and clarity of the information to be collected; 
and (d) minimize the burden on the respondents, including the use of 
automated collection techniques or other forms of information 
technology.
    The PRA also requires agencies to estimate the total annual 
reporting ``non-hour cost'' burden to respondents or recordkeepers 
resulting from the collection of information. We have not identified 
non-hour cost burdens for this information collection. If you have 
costs to generate, maintain, and disclose this information, you should 
comment and provide your total capital and startup cost components or 
annual operation, maintenance, and purchase of service components. You 
should describe the methods you use to estimate major cost factors, 
including system and technology acquisition, expected useful life of 
capital equipment, discount rate(s), and the period over which you 
incur costs. Capital and startup costs include, among other items, 
computers and software you purchase to prepare for collecting 
information; monitoring, sampling, and testing equipment; and record 
storage facilities. Generally, your estimates should not include 
equipment or services purchased: (i) Before October 1, 1995; (ii) to 
comply with requirements not associated with the information 
collection; (iii) for reasons other than to provide information or keep 
records for the Government; or (iv) as part of customary and usual 
business or private practices.
    We will summarize written responses to this proposed information 
collection and address them in our final rule. We will provide a copy 
of the ICR to you without charge upon request and the ICR will also be 
posted on our Web site at http://www.mrm.mms.gov/Laws_R_D/FRNotices/FRInfColl.htm.
    We will post all comments in response to this proposed information 
collection on our Web site at http://www.mrm.mms.gov/Laws_R_D/InfoColl/InfoColCom.htm_. We will also make copies of the comments 
available for public review, including names and addresses of 
respondents, during regular business hours at our offices in Lakewood, 
Colorado. Individual respondents may request that we withhold their 
home address from the public record, which we will honor to the extent 
allowable by law. There also may be circumstances in which we would 
withhold from the rulemaking record a respondent's identity, as 
allowable by law. If you request that we withhold your name and/or 
address, state this prominently at the beginning of your comment. 
However, we will not consider anonymous comments. We will make all 
submissions from organizations or businesses, and from individuals 
identifying themselves as representatives or officials of organizations 
or businesses, available for public inspection in their entirety.

11. National Environmental Policy Act

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

12. Government-to-Government Relationship with Tribes

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

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

    In accordance with Executive Order 13211, this regulation does not 
have a significant effect on the nation's energy supply, distribution, 
or use. The proposed 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 proposed rule 
otherwise impact energy supply, distribution, or use.

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

    In accordance with Executive Order 13175, this proposed rule does 
not have tribal implications that impose

[[Page 50104]]

substantial direct compliance costs on Indian tribal governments

15. Clarity of This Regulation

    Executive Order 12866 requires each agency to write regulations 
that are easy to understand. We invite your comments on how to make 
this rule easier to understand, including answers to questions such as 
the following: (1) Are the requirements in the rule clearly stated? (2) 
Does the rule contain technical language or jargon that interferes with 
its clarity? (3) Does the format of the 56 rule (grouping and order of 
sections, use of headings, paragraphing, etc.) aid or reduce its 
clarity? (4) Would the rule be easier to understand if it were divided 
into more (but shorter) sections? (A ``section'' appears in bold type 
and is preceded by the symbol ``Sec.  '' and a numbered heading; for 
example, Sec.  204.200 What is the purpose of this part?) (5) Is the 
description of the rule in the SUPPLEMENTARY INFORMATION section of the 
preamble helpful in understanding the proposed rule? What else could we 
do to make the rule easier to understand?
    Send a copy of any comments that concern how we could make this 
rule easier to understand to: Office of Regulatory Affairs, Department 
of the Interior, Room 7229, 1849 C Street NW., Washington, DC 20240. 
You may also e-mail the comments to this address: [email protected].

List of Subjects in 30 CFR Parts 206 and 210

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

    Dated: June 23, 2003.
Rebecca W. Watson,
Assistant Secretary for Land and Minerals Management.
    For the reasons set forth in the preamble, subpart C of part 206 
and subpart B of part 210 of title 30 of the Code of Federal 
Regulations are amended as follows:
    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 .S.C. 181 et seq., 351 et seq., 1001 et seq., 1701 
et seq.; 31 U.S.C. 9701; 43 U.S.C. 1301 et seq., 1331 et seq., and 
1801 et seq.

    2. Section 206.101 is amended as follows:
    A. In the definition of ``affiliate'' in paragraph (2), the words 
``between 10 and 50 percent'' are removed and the words ``10 through 50 
percent'' are added in their place.
    B. The definition of ``index pricing'' is removed.
    C. The definition of ``index pricing point'' is removed.
    D. The definition of ``MMS-approved publication'' is revised.
    E. A new definition of ``NYMEX price'' is added in alphabetical 
order.
    F. A new definition of ``prompt month'' is added in alphabetical 
order.
    G. A new definition of ``roll'' is added in alphabetical order.
    H. The definition of ``spot price'' is removed.
    I. The definition of ``trading month'' is revised.
    J. A new definition of ``WTI differential'' is added in 
alphabetical order.
    The additions and revisions to Sec.  206.101 read as follows:


Sec.  206.101.  What definitions apply to this subpart?

* * * * *
    MMS-approved publication means a publication MMS approves for 
determining WTI differentials.
* * * * *
    NYMEX price means the average of the New York Mercantile Exchange 
(NYMEX) settle 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 
- PP2),

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--Falling Market: 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 is the first 
month following the month of production, and May is the second month 
following the month of production. PO 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 PO = $28.00 per bbl, P1 = $27.70 per 
bbl, and P2 = $27.10 per bbl. In this example (a declining 
market), Roll = .6667 - ($28.00 - $27.70) + .3333 - ($28.00 - 27.10) = 
$.20 + $.30 = $.50. You add this number to the NYMEX price.
    (2) Example 2--Rising Market: The month of production for which you 
must determine royalty value is July. July 2003 is the prompt month 
from May 21 through June 20. August is the first month following the 
month of production, and September is the second month following the 
month of production. PO 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 PO = $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

[[Page 50105]]

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, 
Oklahoma, 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). 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.
    Example. Assume the production month is March 2003. Industry trade 
publications perform their price surveys and determine differentials 
during January 26 through February 25 for oil delivered in March. 
(California is an exception. In California, the survey covers the 
calendar month of February for March deliveries.) 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 are published during the period January 26 through 
February 25.
    3. In Sec.  206.103, paragraph (e) is amended as follows:
    A. The paragraph heading is revised to read ``Production delivered 
to your refinery and NYMEX price is an unreasonable value.''
    B. In paragraph (e)(1)(ii), the words ``an index price'' are 
removed and the words ``the NYMEX price'' are added in their place.
    C. In paragraph (e)(1)(iii), the words ``the index price'' are 
removed and the words ``the NYMEX price'' are added in their place, and 
paragraphs (a) through (d) are revised to read as follows:


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

* * * * *
    (a) Production from leases in California or Alaska. Value is the 
NYMEX price, adjusted for applicable location and quality differentials 
and transportation costs under Sec.  206.112.
    (b) Production from leases in the Rocky Mountain Region. This 
paragraph (b) provides methods and options for valuing your production 
under different factual situations. You must consistently apply 
paragraph (b)(1) or (b)(2) or (b)(3) to value all of your production 
from the same unit, communitization agreement, or lease (if 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 production 
from both Federal and non-Federal leases in that 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 one of the other paragraphs. 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, adjusted for applicable location and 
quality differentials and transportation costs under Sec.  206.112.
    (4) If you demonstrate to MMS'' 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 
[EFFECTIVE DATE OF THE FINAL RULE] 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 the roll in this notice.
    (d) Unreasonable NYMEX-based value. If MMS determines that the 
NYMEX price does not represent a reasonable royalty value in any 
particular case, MMS may establish reasonable royalty value based on 
other relevant matters.
* * * * *
    4.-5. In Sec.  206.104, the section heading and paragraphs (a) 
introductory text, (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 based on certain criteria, including, but not 
limited to:
* * * * *
    (3) Publications that use adequate survey techniques, including 
development of estimates based on daily

[[Page 50106]]

surveys of buyers and sellers of crude oil; and
* * * * *
    (c) MMS will reference 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 market values or differentials.
    6. 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. If you value oil using the NYMEX price 
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.
* * * * *
    7. Section 206.110 is amended by:
    A. In paragraph (a), in the first sentence, removing the words 
``under that contract'' and adding in their place the words ``as more 
fully explained in paragraph (b) of this section.''
    B. Redesignating paragraphs (b) through (e) as paragraphs (d) 
through (g).
    C. Adding new paragraphs (b) and (c) to read as follows:


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

* * * * *
    (b) You may deduct any of the following actual costs incurred 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 to a pipeline owner 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 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.
* * * * *
    8. Section 206.111 is amended by:
    A. Revising the section heading and paragraph (a).
    B. Revising paragraph (b) introductory text and adding new 
paragraphs (b)(6) and (b)(7).
    C. In paragraph (h)(5), removing the words ``who owned the system 
on June 1, 2000'' and adding in their place the words ``from whom you 
bought the system. Include in the depreciation schedule any subsequent 
reinvestment.''
    D. In paragraph (i)(2), in the first sentence, adding the words 
``1.5'' before the words ``the industrial bond yield index for Standard 
and Poor's BBB rating.''
    The revisions and additions to the section heading and paragraphs 
(a) and (b) 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:
* * * * *
    (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 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.

[[Page 50107]]

    (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.
* * * * *
    9. 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 the NYMEX price?

    This section applies when you use the NYMEX price 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.
    (a) If you transport or exchange (or both transport and exchange) 
all or a portion of the oil produced from your lease to a market 
center, adjust the NYMEX price for that oil under paragraph (a)(1) or 
(a)(2) of this section, or both, as applicable. If you further exchange 
your oil at arm's length from the market center to Cushing, Oklahoma, 
use paragraph (a)(3)(i) of this section to adjust the NYMEX price for 
that oil between the market center and Cushing, Oklahoma. Otherwise, 
use paragraph (a)(3)(ii) to determine that adjustment. Use paragraph 
(b) or (c) of this section to value the oil that you do not transport 
or exchange to a market center.
    (1) 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.
    (2)(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 adjust the NYMEX price by the applicable location 
and quality differentials derived from your arm's-length exchange 
agreement.
    (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. If MMS prescribes a 
different differential, you must apply MMS' differential to all periods 
for which you used your proposed differential. You must pay any 
additional royalties owed resulting from using MMS' 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).
    (3)(i) For oil that you exchange at arm's length between the market 
center and Cushing, Oklahoma, you must adjust the NYMEX price by the 
applicable location and quality differentials derived from your arm's-
length exchange agreement.
    (ii)(A) For oil that you do not exchange at arm's length between 
the market center and Cushing, Oklahoma, 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 your location and quality differential between the 
market center and Cushing, Oklahoma. (For example, for sweet crude oil 
produced in the Rocky Mountain Region, use the WTI differential for 
Wyoming Sweet crude oil at Guernsey, Wyoming.)
    (B) After you select an MMS-approved publication to calculate the 
WTI differential under paragraph (a)(3)(i) of this section, 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.
    (4) You must determine the adjustments to the NYMEX price under 
paragraphs (a)(1) through (a)(3) of this section for each arrangement 
under which you dispose of production from your lease. For the oil 
disposed of under any one arrangement, you may not claim a 
transportation allowance between the same points between which you 
exchange that oil.
    (5) 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.
    (b) If you transport or exchange (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 value of the portion of the oil 
produced from your lease that is valued using the NYMEX price under 
Sec.  206.103 but that is not transported or exchanged (or both 
transported and exchanged) to or through a market center as follows:
    (1) Determine the volume-weighted average of the adjusted NYMEX 
prices determined under paragraph (a) of this section for the oil that 
you do transport or exchange (or both transport and exchange) from your 
lease to a market center.
    (2) Use that volume-weighted average NYMEX price as the value of 
the oil that you do not transport or exchange (or both transport and 
exchange) from your lease to a market center.
    (3) Example. Assume the same facts as in the example in paragraph 
(a)(5) of this section, 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. Under this 
paragraph (b), the other 60 percent also would be valued at $29.42/bbl.
    (c)(1) 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 a 
differential 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. Use the WTI differential between the 
market center and Cushing, Oklahoma, to adjust

[[Page 50108]]

the NYMEX price between those two points.
    (2) You may use the differential you propose until MMS prescribes a 
different differential.
    (3) If MMS prescribes a different differential, you must apply 
MMS'' differential to all periods for which you used your proposed 
differential. You must pay any additional royalties owed resulting from 
using MMS'' 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).
    (d)(1) If you adjust for location and quality differentials or for 
transportation costs under paragraphs (a), (b), or (c) of this section, 
also adjust the NYMEX price for quality based on premia or penalties 
determined by pipeline quality bank 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), (c), 
and (d)(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 2.5 cents per one-tenth percent difference 
in sulfur content, unless MMS approves a higher adjustment.
    10. Section 206.118 is deleted.
    11. In Sec.  206.119, the first sentence of paragraph (c) is 
removed.
    12. Section 206.121, the section heading and the first sentence are 
revised to read as follows:


Sec.  206.121.  Is there any grace period for reporting and paying 
royalties?

    You may adjust royalties reported and paid for the three production 
months beginning June 1, 2000, without liability for late payment 
interest if those adjustments are reported before [THE DATE THAT IS 90 
DAYS AFTER THE PUBLICATION OF THE FINAL RULE IN THE Federal Register].
* * * * *

PART 210--FORMS AND REPORTS

Subpart B--Oil, Gas, and Sulphur--General

    13. The authority for part 210 is revised to read as follows:

    Authority: 5 U.S.C. 301 et seq.; 25 U.S.C. 396, 396d, 2107; 30 
U.S.C. 189, 190, 359, 1023, 1751(a); 31 U.S.C. 3716, 9701; 43 U.S.C. 
1334, 1801 et seq.; and 44 U.S.C. 2506(a).

    14. In Sec.  210.53, a new paragraph (c) is added to read as 
follows:


Sec.  210.53.  Reporting instructions.

* * * * *
    (c) This paragraph applies if an operator under a joint operating 
agreement is also a designee and reports and pays royalty on behalf of 
one or more working interest owners from whom the operator buys 
production. On the Form MMS-2014, the operator must report the 
following information on separate lines:
    (1) The share of the production the operator purchased from each 
working interest owner and the associated royalty payment; and
    (2) The operator's own share of production and the associated 
royalty payment.

[FR Doc. 03-21217 Filed 8-19-03; 8:45 am]
BILLING CODE 4310-MR-P