Establishing Oil Value for Royalty Due on Federal Leases
Federal RegisterFeb 6, 1998
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DEPARTMENT OF THE INTERIOR
Minerals Management Service
30 CFR Part 206
RIN 1010-AC09
Establishing Oil Value for Royalty Due on Federal Leases
AGENCY: Minerals Management Service, Interior.
ACTION: Supplementary proposed rule.
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SUMMARY: The Minerals Management Service (MMS) is proposing further
changes to its proposed rules amending the regulations governing the
royalty valuation of crude oil produced from Federal leases. MMS is
seeking comments on this proposed rulemaking that includes changes
resulting from comments received on oil valuation proposals published
in the Federal Register and at several hearings and workshops.
DATES: Submit comments on or before March 23, 1998.
ADDRESSES: Send your written comments to David S. Guzy, Chief, Rules
and Publications Staff, Royalty Management Program, Minerals Management
Service, P.O. Box 25165, MS 3021, Denver, Colorado 80225-0165; or e-
Mail David__G[email protected].
FOR FURTHER INFORMATION CONTACT: David S. Guzy, Chief, Rules and
Publications Staff, Royalty Management Program, Minerals Management
Service, telephone (303) 231-3432, fax (303) 231-3385, or e-Mail
David__G[email protected].
SUPPLEMENTARY INFORMATION: The principal authors of this proposed rule
are David A. Hubbard, Charles Brook, and Deborah Gibbs Tschudy of the
Royalty Management Program (RMP) and Peter Schaumberg and Geoff Heath
of the Office of the Solicitor in Washington, D.C.
MMS is specifying a deadline for comments that is less than the 60
days recommended by Executive Order No. 12866. MMS believes that a 45-
day comment period is appropriate in this instance, because it
previously extended and reopened the comment periods for several
earlier proposed versions of this rule. MMS also held numerous
workshops across the country to obtain public input on this proposed
rulemaking. MMS is also planning to hold several hearings during the
45-day comment period to give interested parties the opportunity to
fully discuss and comment on this supplementary proposed rule. MMS will
publish specific dates and locations for the hearings in the Federal
Register. MMS will consider comments filed beyond the deadline to the
extent practicable.
I. Background
MMS first published notice of its intent to amend the current
Federal oil valuation regulations, which appear in 30 CFR part 206, on
December 20, 1995 (60 FR 65610). The goal of this rulemaking effort is
to decrease reliance on oil posted prices, develop valuation rules that
better reflect market value, and add more certainty to valuing oil
produced from Federal lands.
The proposed amendments are brought about by changes in the
domestic petroleum market. Oil postings traditionally represented
prices oil purchasers were willing to pay for particular crude oils in
specific areas. Because they often provided the basis for prices in
arm's-length transactions, MMS generally considered them representative
of market value. Consequently, MMS heavily relied on them for royalty
valuation. However, recent studies commissioned by States and an
analysis performed for MMS by an interagency task force (``Final
Interagency Report on the Valuation of Oil Produced from Federal Leases
in California,'' May 16, 1996) concluded that the postings used by most
companies are considerably less than the true market value of oil.
These studies also indicated that integrated oil companies rarely sell
crude oil at the lease. Instead, they rely on various exchange
arrangements, which do not always reference a price, to transfer oil to
refineries. Even where exchange agreements reference a price, the
transaction's purpose is to exchange oil for oil rather than money for
oil; therefore, MMS cannot rely on the price stated to be reflective of
actual market value.
Based on these studies and subsequent MMS audits and
investigations, MMS believes that the current benchmarks used to value
Federal oil not sold at arm's length, which rely heavily on posted
prices, no longer result in reflecting the market value of the oil.
On January 24, 1997, MMS published its initial notice of proposed
rulemaking to amend the current Federal crude oil valuation regulations
(62 FR 3742). The comment period on this proposal ended March 25, 1997,
but was twice extended to April 28, 1997 (62 FR 7189), and May 28, 1997
(62 FR 19966). We also held public meetings in Lakewood, Colorado, on
April 15, 1997, and Houston, Texas, on April 17, 1997, to hear comments
on the proposal.
In response to the variety of comments received on the initial
proposal, particularly with regard to the limitations on using arm's-
length gross proceeds as value, we published a supplementary proposed
rulemaking on July 3, 1997 (62 FR 36030). The comment period on this
proposal closed August 4, 1997.
Because comments on both proposals were substantial, we reopened
the public comment period on September 22, 1997 (62 FR 49460), and
requested comments on alternatives suggested by commenters before
proceeding with the rulemaking. The initial comment period for this
request closed October 22, 1997, and was extended to November 5, 1997
[[Page 6114]]
(62 FR 55198). We held public workshops to discuss valuation
alternatives in Lakewood, Colorado, on September 30 and October 1, 1997
(62 FR 50544); Houston, Texas, on October 7, 8, and 14, 1997 (62 FR
50544); Bakersfield, California, on October 16, 1997 (62 FR 52518);
Casper, Wyoming, on October 16, 1997 (62 FR 52518); Roswell, New
Mexico, on October 21, 1997 (62 FR 52518); and Washington, D.C. on
October 27, 1997 (62 FR 55198).
After reviewing over 2,600 pages of comments along with records of
the workshops and public meetings, MMS has decided to issue another
supplementary proposed rule. This rule maintains the concept of
``index'' pricing but allows for the use of indicies closer to the
lease and recognizes geographical differences in the marketplace, all
points raised by commenters in response to our earlier proposed
rulemakings. This rule is intended as another of the processes to
develop a rule that meets the needs of the varied constituents.
However, because we are still in the deliberative process, in this
rulemaking, MMS is not responding to the individual comments made on
the five alternatives or on the previous proposals. Once MMS decides on
a framework for a final rule, we intend to thoroughly respond to all
comments received. For this reason, it is not necessary for commenters
to resubmit earlier comments.
II. Summary of Public Comments
This further supplementary proposed rulemaking results from the
comments received in response to the January 24, July 3, and September
22, 1997, notices and from comments made at the public workshops. We
summarized the comments received on the January 24 and July 3, 1997,
proposals in the September 22, 1997, notice. We summarize the comments
received on the September 22, 1997, notice here.
Because of the numerous comments from both States and industry
questioning the use of New York Mercantile Exchange (NYMEX) prices as
the basis for valuing crude oil not sold under arm's-length contracts,
we posed five alternatives, suggested by the commenters, in the
September 22, 1997, notice to value ``non-arm's-length'' oil: (1) A
value based on prices received under bid-out or tendering programs; (2)
a value determined from benchmarks using arm's-length transactions,
royalty-in-kind (RIK) sales, or a netback method; (3) a value based on
geographic indexing using MMS's own system data, but excluding posted
prices; (4) a value based on index (NYMEX and ANS) prices but using
fixed-rate differentials; and (5) a value using published spot prices
instead of NYMEX prices. With regard to Alternatives 1, 2, and 3, we
also asked whether the Rocky Mountain Area should have separate and
specific valuation standards.
We received 28 written comments from independent oil and gas
producers, major oil and gas companies, petroleum industry trade
associations, States, a municipality, a government oversight group, and
a royalty owner. Sixty individuals provided commentary at the public
workshops. The summary of comments follows.
Alternative 1--Bid-Out or Tendering Program
Industry and some States supported tendering as a viable
alternative to determine value at the lease. They assert that the
prices received under tendering transactions were evidence of market
value at or near the lease. However, industry cautioned that tendering
would not be applicable in every situation (it would be too expensive
for some companies to develop and administer) and should be only used
as one of several alternatives available for valuation. In fact, two
commenters noted that tender-based valuation was not feasible in
California because no one is presently engaged in tendering programs in
that State. To be acceptable for valuing the lessee's non-arm's-length
production, one commenter recommended that the minimum tendered volume
should be MMS's royalty share plus 2 percent, or if transported by a
truck or tank car, a volume equal to a full load. Another commenter
recommended 10 to 20 percent as the minimum volume, with a minimum of
three bids.
Alternative 2--Benchmarks
Industry and some States generally supported some form of benchmark
system based on actual arm's-length or affiliate resale prices, RIK
prices, or a netback method using an index price to value non-arm's-
length oil. (Nonetheless, many commenters remained opposed to NYMEX-
and ANS-based pricing.) Industry, however, advocated that lessees be
permitted to select the valuation method best suited to their
situation; in other words, they wanted the benchmarks to be a menu,
rather than a hierarchy. States objected to this selection concept.
Industry also urged MMS to abandon the requirement that royalty value
is the greater of the lessee's gross proceeds or the benchmark value.
One State recommended separate valuation standards for lessees with
affiliated refiners and those without. That State also recommended, for
the Rocky Mountain region only, that lessees with affiliated refiners
determine value by benchmarks using tendered prices, lease-based
comparable sales, and netback from spot price. It further recommended,
for all lessees without affiliated refiners who sell their oil non-
arm's-length, that value be based on the oil's resale price. Industry
objected to this affiliated-refiners distinction because they stated
not all integrated producers sell or transfer their oil production to
their affiliated refiner.
For netback valuation, industry urged MMS to recognize all costs
associated with midstream marketing as allowable deductions from the
index or resale price. However, one State commenter argued that
industry has failed to demonstrate any entitlement to a marketing
deduction as a matter of law or fact, citing, for example, that
midstream marketing costs are already factored into transportation
tariffs and location differentials.
Two commenters representing State of California interests objected
to any benchmark valuation scheme for that State. They argued that the
California crude oil market is not competitive. Thus, they believed
that any non-arm's-length valuation scheme based on arm's-length prices
would not reflect true market value. They maintained that ANS prices
are the only viable method of valuing crude oil in California.
Alternative 3--Geographic Indexing
Most commenters believed the proposed geographic indexing method
would be unworkable. They mainly objected to the time difference
between the production month and publication of the index price. They
argued that the published indices always would be out of date and
require unnecessary adjustments to prior reporting months.
Alternative 4--Differentials
In concert with their objections to basing value on index (NYMEX
and ANS) prices, industry commenters opposed using any fixed (or other)
differentials without deductions for midstream marketing activities.
Specifically for California, two commenters representing State
interests urged MMS to use the gravity factor in the Four Corners and
All America Pipeline tariffs to adjust for quality differences between
ANS and California crude oils. For location differentials, they
reiterated their position that the only relevant information is from
``in/out'' exchanges. As an option to determining separate location
differentials for the various California
[[Page 6115]]
aggregation points/market center pairs, they proposed fixed-rate
differentials for given geographic zones.
Alternative 5--Spot Prices
Comments on the proposed spot price methodology were mixed. Some
commenters thought it was a workable approach, indicating that the net
result would be the same as starting with a NYMEX price and adjusting
back to the lease. A few commenters noted that spot prices are
published only for a limited number of domestic crude oils, and no
reliable spot prices are published for the Rocky Mountain Area. One
commenter questioned the accuracy of the reported prices. Industry
commenters remained concerned with the disallowance of marketing costs
in using spot prices, but in general, preferred spot prices to NYMEX.
Rocky Mountain Area
There was general consensus among commenters that the Rocky
Mountain Area exhibited particular oil marketing characteristics that
would justify different royalty valuation standards. Production is
controlled by relatively few companies in the Rocky Mountain Area. The
number of buyers is also more limited than in the Texas, Gulf Coast, or
Mid-continent areas and there are limited third party shippers and less
competition for transportation services in this area. Finally, there is
less spot market activity and trading in this area as a result of this
control over production and refining and because crude oil production
is smaller and more diffuse than in the Gulf Coast and Permian Basin
areas. Some commenters, both industry and State, supported the notion
of separate valuation standards for the region. Others, however,
disagreed with any regional separation, preferring instead a single,
nationwide, lease-based valuation scheme or menu of benchmarks.
III. Section-by-Section Analysis
The content of many of the sections has not changed significantly
from the January 1997 notice of proposed rulemaking, but we rewrote the
proposed rule to better reflect plain English. We also added and
renumbered sections and further reorganized the rule for readability.
This preamble focuses primarily on those sections whose content we
significantly changed. While the preambles of the January 1997 proposed
rule and the July 1997 supplementary proposed rule discuss earlier
changes, this preamble highlights changes that have been made as a
result of comments received throughout this rulemaking. Note that the
renumbering and reorganization resulted in the following modifications
to the previous proposals:
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Section Modification
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Secs. 206.100 and 206.101... Revised.
Sec. 206.102................ Revised and redesignated as Secs.
206.102, 206.103, 206.104, 206.105,
206.106, 206.107, and 206.108.
Secs. 206.103 and 206.104... Redesignated as Secs. 206.122 and
206.109, respectively.
Sec. 206.105................ Revised and redesignated as Secs.
206.110, 206.111, 206.116, 206.117,
206.119, 206.120, and 206.121.
Sec. 206.106................ Revised and redesignated as Sec.
206.123.
New Secs. 206.112, 206.113, Added.
206.114, 206.115, and
206.118.
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In addition, all sections of the existing rule not previously
proposed to be revised were rewritten in plain English so the entire
rule would read consistently.
Before proceeding with the section-by-section analysis, it is
necessary to explain the conceptual framework of the proposed rule.
When crude oil is produced, it is either sold at arm's length or is
refined without ever being sold at arm's length. If crude oil is
exchanged for other crude oil at arm's length, the oil received in the
exchange is either sold at arm's length or is refined without ever
being sold at arm's length. Under this proposed rule, oil that
ultimately is sold at arm's length before refining generally will be
valued based on the gross proceeds accruing to the seller under the
arm's-length sale. (The few exceptions reflect particular circumstances
in which MMS believes the arm's-length sale does not or may not
reliably reflect the real value.) Similarly, if oil is exchanged at
arm's length and the oil received in exchange is ultimately sold at
arm's length, the value of the oil produced will be based on the arm's-
length sale of the oil received in exchange, with appropriate
adjustments. If oil (or oil received in exchange) is refined without
being sold at arm's length, then the value will be based on appropriate
index prices or other methods, as explained below.
These principles apply regardless of whether oil is sold or
transferred to one or more affiliates or other persons in non-arm's-
length transactions before the arm's-length sale, and regardless of the
number of those non-arm's-length transactions. They also apply
regardless of how many arm's-length exchanges have occurred before an
arm's-length sale. Lessees and producers may structure their business
arrangements however they wish, but MMS would look to the ultimate
arm's-length disposition in the open market as the best measure of
value. Similarly, if oil is refined without being sold at arm's length,
MMS believes that the valuation methods prescribed in this proposed
rule are the best measures of value regardless of internal, inter-
affiliate, or other non-arm's-length transfers.
Another important concept of the proposed rule is that MMS is
proposing separate valuation procedures for California/Alaska, the
Rocky Mountain Area, and the rest of the country. In California and
Alaska, if oil is not sold under an arm's-length contract, value would
be based on ANS spot prices, adjusted for location and quality. MMS
chose this indicator because it believes, as the interagency task force
concluded, that ANS is the best measure of market value in that area
when oil is not sold at arm's length. In the Rocky Mountain Area, if
oil is not sold under an arm's-length contract, market value is more
difficult to measure because of the isolated nature of the Area from
the major oil market centers. Therefore, MMS is proposing to accept
values established by a company-administered tendering program as the
first benchmark. In cases where tendering does not happen or it does
not meet our requirements, the second benchmark would be a weighted-
average of arm's-length sales and purchases exceeding 50 percent of the
lessee's and its affiliate's production in the field or area. NYMEX
with location and quality adjustments would be used as the third
benchmark, because no acceptable published spot price exists in the
Rocky Mountain
[[Page 6116]]
Area. For other areas, value would be based on the nearest spot price,
adjusted for quality and location. MMS believes that because the spot
market is so active in areas other than the Rocky Mountain Area, it is
the best indicator of value. MMS chose spot prices over NYMEX because
studies indicated that when the NYMEX futures price, properly adjusted
for location and quality differences, is compared to spot prices, it
nearly duplicates those spot prices. Further, application of spot
prices would remove one portion of the necessary adjustments to the
NYMEX price--the leg between Cushing, Oklahoma, and the market center
location.
Proposed Section 206.100 What is the Purpose of this Subpart?
This section includes the content of the existing section except
for minor wording changes to improve clarity. We have added some
further language clarifying the respective roles of lessees and
designees. (Those terms are defined in the proposed Sec. 206.101, and
those definitions follow the definitions contained in section 3 of the
Federal Oil and Gas Royalty Management Act, 30 U.S.C. 1702, as amended
by section 2 of the Federal Oil and Gas Royalty Simplification and
Fairness Act, Pub. L. No. 104-185, 110 Stat. 1700.)
Specifically, if you are a designee and you or your affiliate
dispose of production on behalf of a lessee, references to ``you'' and
``your'' in the proposed rule refer to you or your affiliate. In this
event, you must report and pay royalty by applying the rule to your and
your affiliate's disposition of the lessee's oil. If you are a designee
and you report and pay royalties for a lessee but do not dispose of the
lessee's production, the references to ``you'' and ``your'' in the
proposed rule refer to the lessee. In that case, you as a designee
would have to determine royalty value and report and pay royalty by
applying the rule to the lessee's disposition of its oil. Some examples
will illustrate the principle.
Assume that the designee is the unit operator, and that the
operator sells all of the production of the respective working interest
owners on their behalf and is the designee for each of them. For each
of those working interest owners, the operator, as designee, would
report and pay royalties on the basis of the operator's disposition of
the production. For example, if the operator transferred the oil to its
affiliate, who then resold the oil at arm's length, the royalty value
would be the gross proceeds accruing to the designee's affiliate in the
arm's-length resale under proposed Sec. 206.102, as explained further
below.
Alternatively, assume the operator is the designee but a lessee
disposes of its own production. Assume the lessee transfers its oil to
an affiliate, who then resells the oil at arm's length. In this case,
the operator would have to obtain the information from the lessee, and
report and pay royalties on the basis of the gross proceeds accruing to
the lessee's affiliate in the arm's-length resale under proposed
Sec. 206.102.
In some cases, the designee is the purchaser of the oil. Assume the
operator disposes of the lessee's oil and that the operator is not
affiliated with the designee-purchaser. Because the lessee's sale to
the designee is an arm's-length transaction, then under Sec. 206.102
the designee would report and pay royalty on the total consideration
(the gross proceeds) it paid to the lessee.
Proposed Section 206.101 Definitions
The definitions section remains largely the same as in the January
1997 notice of proposed rulemaking. However, MMS made several additions
and clarifications consistent with changes in this further
supplementary proposed rule.
Specifically, the July 3, 1997, supplementary proposed rule (62 FR
36030) added a definition of non-competitive crude oil call to help
describe circumstances under which crude oil sales proceeds could be
used for royalty valuation. We incorporated a simplified version of
that definition in this further supplementary proposed rule, as well as
a new definition of competitive crude oil call to assist in
understanding the differences between these two contract terms.
We modified the definition of arm's-length contract to remove the
criteria for determining affiliation. Instead, these criteria would be
included in the new definition of affiliate discussed below.
We also modified the definition of exchange agreement to delete the
statement that exchange agreements do not include agreements whose
principal purpose is transportation. MMS believes that transportation
exchanges, while having different purposes than other types of
exchanges, properly should be included under the generic definition of
exchange agreements.
We also modified the definition of gross proceeds to clarify that
they would include payments made to reduce or buy down the purchase
price of oil to be produced later. The concept that such payments are
part of gross proceeds was included in the January 1997 proposed
rulemaking at Sec. 206.102(a)(5). Moving this provision directly to the
gross proceeds definition not only further clarifies the components of
gross proceeds, but also makes the structure of this further
supplementary proposed rule more logical.
Also, since this further supplementary proposed rule would apply
spot prices for crude oil other than Alaska North Slope oil as a
valuation basis in some cases, we changed the definitions of index
pricing and MMS-approved publication to include other spot prices.
Finally, we added four new definitions of terms used in this
further supplementary proposed rule. They are affiliate, prompt month,
Rocky Mountain Area, and tendering program.
MMS requests comments on the Rocky Mountain Area definition.
Specifically, are there other States or regions that should be included
in this definition and, conversely, are there States or regions that
should be deleted? For example, although some participants in MMS's
workshops believed the entire State of New Mexico belongs outside the
Rocky Mountain Area for purposes of applying this rule, others believed
that oil marketing in the northwest portion of New Mexico is similar to
that in the other Rocky Mountain States. Some commenters suggested that
northwest New Mexico (not including the Permian Basin) more
appropriately should be included in the Rocky Mountain Area. MMS has
excluded New Mexico from the proposed definition but would like
comments on this issue.
MMS also requests any other comments you may have on these proposed
new and revised definitions.
Proposed Section 206.102 How Do I Calculate Royalty Value for Oil That
I or My Affiliate Sell Under an Arm's-Length Contract?
In an effort to improve the organization and readability of the
proposed rule, Sec. 206.102 as written in the January 1997 proposed
rule and the July 1997 supplementary proposed rule would be revised and
reorganized. We propose to revise Sec. 206.102 to specifically address
valuation of oil ultimately sold under arm's-length contracts. That
sale may occur in the first instance, or may follow one or more non-
arm's-length transfers or sales of the oil or one or more arm's-length
exchanges.
Paragraph (a) would state that value is the gross proceeds accruing
to you or your affiliate under an arm's-length contract, less
applicable allowances. This also includes oil you sell in exercising a
competitive crude oil call. Similarly, if you sell or transfer your
Federal oil production to some other person at less than arm's length,
and
[[Page 6117]]
that person or its affiliate then sells the oil at arm's length,
royalty value would be the other person's (or its affiliate's) gross
proceeds under the arm's-length contract. For example, a lessee might
sell its Federal oil production to a person who is not an ``affiliate''
as defined, but with whom its relationship is not one of ``opposing
economic interests'' and therefore is not at arm's length. An
illustrative example would be a number of working interest owners in a
large field forming a cooperative venture that purchases all of the
working interest owner's production and resells the combined volumes to
a purchaser at arm's-length. The sale proceeds then would be
distributed proportionately to those persons who contributed volumes.
Xeno, Inc., 134 IBLA 172 (1995), involved a similar situation in the
context of a gas field. If no one of the working interest owners owned
10 percent or more of the new entity, the new entity would not be an
``affiliate'' of any of them. Nevertheless, the relationship between
the new entity and the respective working interest owners would not be
at arm's length. In this instance, it would be appropriate to value the
production based on the arm's-length sale price the cooperative venture
received for the oil.
In all these circumstances you would be required to value the
production based on the gross proceeds accruing to you, your affiliate,
or other person to whom you transferred the oil when the oil ultimately
was sold at arm's length.
Proposed paragraph (b) would clarify how to value your oil when you
sell or transfer it to your affiliate or to another person, and your
affiliate, the other person, or an affiliate of either of them sells
the oil at arm's-length under multiple arm's-length contracts. In this
case, value would be the volume-weighted average of the values
established under Sec. 206.102 for each contract.
However, paragraph (c), which replaces paragraph (a)(1) from the
January 1997 proposed rule, specifies several exceptions to the use of
arm's-length gross proceeds. As stated in the July 1997 supplementary
proposed rule, it would also require you to apply the exceptions to
each of your contracts individually. For example, you may have multiple
arm's-length and non-arm's-length exchange agreements involving your
Federal oil production. Depending on its ultimate disposition under
each exchange agreement, you might value some of the production under
Sec. 206.102 and some under Sec. 206.103.
Proposed paragraphs (c)(1) and (c)(2) would replace paragraphs
(a)(2) and (a)(3) from the January 1997 proposed rule. Although the
wording changes slightly, the content remains the same. Note, however,
that in the supplementary proposed rule of July 3, 1997, a proposed
revision under paragraph (a)(4)(ii) said that where an arm's-length
contract price does not represent market value because an overall
balance between volumes bought and sold is maintained between the buyer
and seller, royalty value would be calculated as if the sale were not
arm's length. MMS decided to remove that language as a specific,
separate provision. Rather, in considering whether an arm's-length
contract reflects your or your affiliates' total consideration or
market value (proposed paragraphs (c)(1) and (c)(2)), MMS also would
examine whether the buyer and seller maintain an overall balance
between volumes they bought from and sold to each other. Under these
paragraphs, if an overall balance agreement is found to exist, you
would be required to value your production under Sec. 206.103 or the
total consideration received, whichever is greater.
In the supplementary proposed rule of July 3, 1997, MMS proposed to
modify paragraph (a)(4) of the January 1997 proposed rule regarding
exchange agreements and crude oil calls. It also proposed a new
paragraph (a)(6) regarding exchange agreements. See the preamble to the
supplementary proposed rule at 62 FR 36031 for a complete explanation
of the changes proposed. In this further supplementary proposed rule,
we have further modified the exchange agreement language at paragraphs
(a)(4)(i) and (a)(6) of the supplementary proposed rule and combined it
in paragraph (c)(3). Revised paragraph (c)(3) would require you to use
Sec. 206.103 to value oil you dispose of under an exchange agreement.
But if you enter into one or more arm's-length exchange agreements, and
after these exchanges you or your affiliate dispose of the oil in an
arm's-length sale, you would value the oil under paragraph (a) on the
basis of the gross proceeds received under the arm's-length contract
for the sale of the oil received in exchange. You would adjust the
value determined under paragraph (a) for location or quality
differentials or any other adjustments you receive or pay under the
arm's-length exchange agreement(s). However, if MMS finds that any such
differentials or adjustments aren't reasonable, it could require you to
value the oil under Sec. 206.103.
This concept is similar to paragraph (6)(i) of the July 1997
supplementary proposed rule, but with three differences. First, the
July language referred to exchange agreements with a person not
affiliated with you. The revision proposed here would expand coverage
to arm's-length exchange agreements. This means that not only must you
be unaffiliated with your exchange partner, but there must be opposing
economic interest regarding the exchange agreement. MMS believes this
would limit instances where inappropriate or unreasonable location,
quality, or other adjustments would be applied. MMS proposes to limit
this provision to arm's-length exchanges because it believes
transportation, location, and quality differentials stated in non-
arm's-length exchange agreements are not reliable.
Second, MMS proposes to clarify that the same valuation procedure
would apply if there is more than one arm's-length exchange. For
example, if you enter into two sequential arm's-length exchanges for
your Federal oil production and then you or an affiliate sell the
reacquired oil at arm's length, you would value your production under
paragraph (a). MMS believes that as long as the integrity of the
differentials and adjustments is maintained, there is no reason not to
look to the ultimate arm's-length sale proceeds.
Third, under paragraph (a)(6)(i) of the supplementary proposed
rule, if you disposed of your oil under an exchange agreement with a
non-affiliate and after the exchange you sold the acquired oil at arm's
length, you could have elected to value your oil either at your gross
proceeds or under index pricing. MMS proposes to eliminate this option.
We believe that the actual arm's-length disposition should govern
valuation. That is, the provisions of Secs. 206.102 or 206.103 should
be applied according to your actual circumstances. This change also
leads to the deletion of the previously-proposed paragraph (a)(6)(iii),
which related to the election we now propose to eliminate.
As a result of the changes discussed above, MMS also proposes to
eliminate paragraph (a)(6)(ii) of the July 1997 supplementary proposed
rule. This paragraph would have required you to use index pricing if
you either transferred your oil to an affiliate before the exchange
occurred, transferred the oil you received in the exchange to an
affiliate, or entered into a second exchange for the oil you received
back under the first exchange. We have already discussed the
permissibility of multiple exchanges under this further supplementary
proposed rule. Our reasoning for eliminating the rest of paragraph
(a)(6)(ii) of the July 1997
[[Page 6118]]
supplementary proposed rule is that if you transfer your production to
an affiliate and the affiliate then enters into an arm's-length
exchange and sells the oil received in the exchange at arm's length,
the arm's-length proceeds should be the measure of value. Likewise, if
you enter an arm's-length exchange but then transfer the oil received
to an affiliate who resells the oil at arm's length, the arm's-length
proceeds should be the measure of value. For any exchanges where the
oil received in return is not resold but instead is refined, index
prices would apply as discussed under Sec. 206.103.
Proposed paragraph (c)(4) would remain essentially the same as
paragraph (a)(4)(iii) of the supplementary proposed rule. It states
that you must use Sec. 206.103 to value oil you dispose of in
exercising a non-competitive crude oil call. In response to the
supplementary proposed rule and in MMS's public workshops, commenters
asserted that in many instances producers negotiate competitive prices
even if a non-competitive call provision exists and a call on
production is exercised. However, we continue to believe that if your
purchaser exercises a non-competitive call, you could not effectively
demonstrate that the price received is competitive and that value
should be determined using index pricing.
Paragraph (a)(5) of the January 1997 proposed rule dealt with
inclusion in gross proceeds of payments made to reduce or buy down the
price of oil to be produced in later periods. We removed this paragraph
in this further supplementary proposed rulemaking but added the concept
within the definition of gross proceeds as discussed above.
Currently-proposed Sec. 206.102 (d), What else must I do if I value
oil under paragraph (a)?, has the same content as Sec. 206.102 (b) of
the January 1997 proposed rule. A minor difference is a clarification
that you must be able to demonstrate that an exchange agreement, as
well as a contract, is arm's length. Also, since this further
supplementary proposed rule would require arm's-length gross proceeds
as royalty value regardless of whether the lessee or an affiliate or
another arm's-length purchaser is the person who ultimately sells at
arm's length, all of these persons come within the term ``seller.''
Proposed Section 206.103 How Do I Value Oil That I Cannot Value Under
Sec. 206.102?
This section would replace Sec. 206.102(c) of the January 1997
proposed rule. It deals specifically with valuation of oil you cannot
value under Sec. 206.102 because the oil is not ultimately sold at
arm's length or because it is otherwise excepted under Sec. 206.102.
One change from the January 24, 1997, proposal would apply where
value is based on index prices. In MMS' initial proposal, where either
NYMEX or spot prices were applied in valuation, the prices for the
month following the lease production month were used. This was meant to
reflect the fact that NYMEX futures prices for the prompt month, as
well as spot prices for the next month, are determined during the month
of production. MMS believed this best reflected market value at the
time of production. However, various commenters asserted that, for
application of spot or futures prices, the lease production month
should coincide with the spot or futures delivery month. This would
effectively match production to index prices for deliveries in the same
month. Although we believe the effects of such a change over time would
be minimal, we now propose to change the timing of application of index
prices so that the lease production month and the spot or futures
delivery month would coincide.
Also, Sec. 206.102(c)(1) of the January 1997 proposed rule would
have permitted you an option if you first transferred your oil
production to an affiliate and that affiliate or another affiliate
disposed of the oil under an arm's-length contract. The option was to
value your oil at either the gross proceeds accruing to your affiliate
under its arm's-length contract or the appropriate index price. But
this option is not available in this further supplementary proposed
rule. MMS believes that where arm's-length transactions satisfying the
provisions of proposed Sec. 206.102 occur, royalty value should be the
arm's-length gross proceeds. Otherwise, the provisions of this proposed
Sec. 206.103 should apply directly. This process would remove some
uncertainty among lessees about how and when to apply this section.
More importantly, MMS believes this process best reflects the actual
value of the oil.
Another change from January proposed rule is an additional
geographic breakdown for valuation purposes. The original proposed rule
included separate valuation procedures for California/Alaska and the
rest of the country. But based on the various written comments MMS
received in response to its January, July, and September 1997
rulemaking notices, and comments made at the various valuation
workshops, it became apparent that oil marketing and valuation in the
Rocky Mountain Area is significantly different from other areas.
Also, the only published spot price in the Rocky Mountain Area is
at Guernsey, Wyoming. Commenters consistently maintained that the spot
price there is thinly traded. The combination of geographical
remoteness from midcontinent markets, unique marketing situations, and
the lack of a meaningful published spot price led MMS to add the Rocky
Mountain Area as a third royalty valuation area. MMS requests comments
on the revised geographical breakdown for valuation purposes, as well
as the composition of the Rocky Mountain Area.
Proposed Sec. 206.103(a) would apply to production from leases in
California or Alaska. It would replace Sec. 206.102(c)(2)(ii) of the
January 1997 proposed rule. The only differences in this further
supplementary proposed rule are a more direct explanation of how to
calculate the spot prices and a clarification that the applicable spot
prices are those published during the month preceding the production
month. To calculate the daily mean spot prices, you would average the
published daily high and low prices for the applicable month, only
using the days and corresponding prices for which spot prices are
published. You would not include weekends, holidays, or any other days
when spot prices are not published. For example, assume the month
preceding the production month has 31 days, including 8 weekend days
and a holiday, and the publication publishes spot prices for all other
days. You would average together the published high and low spot prices
for each of the 22 remaining days.
Proposed Sec. 206.103(b) would apply to production from leases in
the Rocky Mountain Area, a defined term. As discussed above, production
in the Rocky Mountain Area is controlled by relatively few companies
and the number of buyers is more limited than in the Texas, Gulf Coast,
or Mid-contintent areas. As a result, there is less spot market
activity and trading in this area due to the control over production
and refining. For these reasons, we derived the following valuation
hierarchy for Rocky Mountain Area:
[[Page 6119]]
(1) If you have an MMS-approved tendering program (a defined term),
the value of production from leases in the area the tendering program
covers would be the highest price bid for tendered volumes. Under
tendering program you would have to offer and sell at least 33\1/3\
percent of your production from both Federal and non-Federal leases in
that area. You also would have to 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.
To ensure receipt of market value under tendering programs, MMS
proposes the several qualifications listed above. First, royalty value
must be the highest price bid rather than some other individual or
average value. Second, you must offer and sell at least 33\1/3\ percent
of your production from both Federal and non-Federal leases in that
area. The rationale for this minimum percentage is to ensure that the
lessee puts a sufficient volume of its own production share up for bid
to minimize the possibility that it could ``game'' the system for
Federal royalty or State tax payment purposes. MMS chose the 33\1/3\
percent figure because it exceeds the typical combined Federal royalty
rate and effective composite State tax and royalty rates for onshore
oil leases by roughly 10 percent. Likewise, the tendering program would
be required to include non-Federal lease production volumes in the
33\1/3\ percent determination to ensure that the program isn't aimed at
limiting Federal royalty value.
Third, to ensure receipt of competitive bids, your tendering
program must result in at least three bids from bidders who do not have
their own tendering programs covering some or all of the same area. MMS
believes that requiring a minimum number of bidders is needed to ensure
receipt of market value. Further, MMS is concerned about the
possibility of cross-bidding between companies at below-market prices,
which could otherwise satisfy the minimum number of bidders
requirement. That is why we added the stipulation that bids must come
from bidders who do not also have their own tendering programs in the
area.
MMS requests comments on use of tendering programs in general in
establishing royalty value. Also, please provide comments on the
proposed specific qualifications. Should we limit qualified bids to
those who do not have tendering programs anywhere, and not just in the
same area? Should a tendering program be a first or second benchmark?
Please provide any related comments you may have.
(2) Under the second criterion, which would apply only if you could
not use the first criterion, value would be the volume-weighted average
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. 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.
MMS proposes this method as the next alternative if a qualified
tendering program does not exist. It is an effort to establish value
based on actual transactions by the lessee or its affiliate(s). We
received a number of comments during the public workshops that MMS
should look not only to sales by the lessee, but also purchases a
lessee or its affiliates make in the field or area. Just as for the
tendering program, MMS believes a floor of the lessee's and its
affiliates' production should be set to prevent any ``gaming.'' The 50
percent minimum figure is not necessarily a higher standard than the
33\1/3\ percent floor associated with the tendering program, because it
applies to the lessee's and its affiliates' sales and purchases in the
field or area. For example, Company A produces 10,000 barrels of crude
oil in a given field during the production month. Company A sells 1,000
barrels under an arm's-length contract. Company A also has a refining
affiliate, Company B, that purchases the remaining 9,000 barrels of
Company A's production and 5,000 barrels of oil under arm's-length
purchase contracts with other producers in the same field. Together the
arm's-length sales by Company A and the arm's-length purchases by
Company B are 6,000 barrels, or 60 percent of the lessee's and its
affiliates' production in the field that month. The volume-weighted
arm's-length gross proceeds accruing to Company A and paid by Company B
for these 6,000 barrels represents royalty value for the 9,000 barrels
of Company A's Federal lease production in the field that cannot be
valued under Sec. 206.102.
MMS proposes using the unadjusted volume-weighted average gross
proceeds accruing to the seller in all of the lessee's or its
affiliates' arm's-length sales or purchases, not just those that may be
considered comparable by quality or volume. We believe that production
in the same field or area generally will be similar in quality.
Further, given that these sales and purchases must be greater than 50
percent of all of the lessee's production in the field or area, we
believe that it is not necessary to distinguish comparable contracts.
(3) If you could not apply either of the first two criteria, the
value would be the average of the daily NYMEX futures settle prices at
Cushing, Oklahoma, for the light sweet crude oil contract for the
prompt month that is in effect on the first day of the month preceding
the production month. You would use only the days and corresponding
NYMEX prices for which such prices are published. You must adjust the
value for applicable location and quality differentials, and you may
adjust it for transportation costs, under Sec. 206.105(c) of this
subpart.
This paragraph essentially duplicates Sec. 206.102(c)(2)(i) of the
January 1997 proposed rule. The only real difference is that we
correlated the NYMEX futures delivery month with the production month
as discussed earlier. As described for the spot price calculations for
California and Alaska, you would use only the days for which NYMEX
futures prices are published. MMS proposes to make this the third
method, to be used only if the first two do not apply, because of
distances between Rocky Mountain Area locations and Cushing, Oklahoma,
and the additional difficulties in deriving location/quality
differentials.
(4) If you should demonstrate to MMS' satisfaction that paragraphs
(b)(1) through (b)(3) result in an unreasonable value for your
production as a result of circumstances regarding that production, the
MMS Director could establish an alternative valuation method.
MMS proposes this method as the last alternative, to be used only
in very limited and highly unusual circumstances. We also propose that
there should be very few such alternative valuation methods and each
one should be subject to careful review.
Proposed Sec. 206.103(c) would apply to production from leases not
located in California, Alaska, or the Rocky Mountain Area. MMS proposes
to modify Sec. 206.102(c)(2)(i) of the January 1997 proposed rule that
applied to locations other than California and Alaska. That paragraph
would have required you to value your oil at the average daily NYMEX
futures settle prices. This further supplementary proposed rule would
state that value is the average of the daily mean spot prices:
(1) For the market center nearest your lease where spot prices are
published in an MMS-approved publication;
[[Page 6120]]
(2) For the crude oil most similar in quality to your oil (for
example, at the St. James, Louisiana, market center, spot prices are
published for both Light Louisiana Sweet and Eugene Island crude oils.
Their quality specifications differ significantly); and
(3) For deliveries during the production month.
You would calculate the daily mean spot price by averaging the
daily high and low prices for the month in the selected publication.
You would also use only the days and corresponding spot prices for
which such prices are published. You would be required to adjust the
value for applicable location and quality differentials, and you would
be permitted to adjust it for transportation costs, under Secs. 206.112
and 206.113 of this subpart.
Another difference from the January 1997 proposed rule is the
application of spot, rather than NYMEX, prices. MMS made this change
for several reasons. First, we believe that when the NYMEX futures
price, properly adjusted for location and quality differences, is
compared to spot prices, it nearly duplicates those spot prices.
Second, application of spot prices would remove one portion of the
necessary adjustments to the NYMEX price--the leg between Cushing,
Oklahoma, and the market center location.
MMS did not propose any of the alternatives here that it proposes
for the Rocky Mountain Area for oil that cannot be valued under
proposed Sec. 206.102. That is because, unlike the Rocky Mountain Area,
there are meaningful published spot prices applicable to production in
the other areas (Cushing, Oklahoma; St. James, Louisiana; Empire,
Louisiana; Midland, Texas). With the exception of the Rocky Mountain
Area, in the United States, spot and spot-related prices drive the
manner in which crude oil is bought and traded. Spot prices play a
significant role in crude oil marketing in terms of the basis upon
which deals are negotiated and priced and are readily available to
lessees via price reporting services. We believe that spot prices are
the best indicator of value for production from leases not located in
California, Alaska, or the Rocky Mountain Area; therefore, it is not
necessary to consider other less accurate means of valuing production
not sold arm's-length from this area.
MMS is not proposing to allow the costs of marketing production as
an allowable deduction from index or gross proceeds-based pricing. The
lease requires the lessee to market production at no cost to the
lessor. The Interior Board of Land Appeals has consistently upheld MMS
on this position. See Walter Oil and Gas Corp., 111 IBLA 260, 265
(1989), October 25, 1989, and Arco Oil and Gas Co., 112 IBLA 8, 11
(1989). Therefore, in this proposed rule MMS is not altering its long-
standing policy.
Proposed Sec. 206.103(d) is Sec. 206.102(c)(3) of the January 1997
proposed rule with minor clarifying word changes. If MMS determines
that any of the spot or NYMEX-based prices are no longer available or
no longer represent market value, then MMS will exercise the
Secretary's authority to establish value based on other relevant
matters including well-established market basket formulas.
Proposed Section 206.104 What Index Price Publications Are Acceptable
to MMS?
Proposed Sec. 206.104 is paragraphs (c)(4), (c)(5), and (c)(6) of
Sec. 206.102 from the January 1997 proposed rule with an added
reference to spot prices for crude oil other than ANS.
Proposed Section 206.105 What Records Must I Keep to Support My
Calculations of Value Under This Subpart?
Proposed Sec. 206.105 is a clarification that you must be able to
show how you calculated the value you reported, including all
adjustments. This is important because if you are unable to demonstrate
on audit how you calculated the value you reported to MMS, you could be
subjected to sanctions for false reporting.
Proposed Section 206.106 What Are My Responsibilities to Place
Production Into Marketable Condition and to Market Production?
Proposed Sec. 206.106 is Sec. 206.102(e)(1) of the January 1997
proposed rule with minor clarifying word changes. Also, MMS proposes to
delete Sec. 206.102(e)(2) of the January 1997 proposed rule. It
referred to potential improper value determinations and related
interest, which are already covered in other parts of MMS's
regulations.
Proposed Section 206.107 What Valuation Guidance Can MMS Give Me?
Proposed Sec. 206.107 includes the substance of Sec. 206.102(f) of
the January 1997 proposed rule in shortened and simplified terms. Also,
MMS proposes to delete Sec. 206.102(g) of the January 1997 proposed
rule. It discussed audit procedures related to value determinations,
and these are covered sufficiently in other parts of MMS's regulations.
Proposed Section 206.108 Does MMS Protect Information I Provide?
Proposed Sec. 206.108 is Sec. 206.102(h) of the January 1997
proposed rule, but with minor wording changes for clarity.
Proposed Section 206.109 When May I Take a Transportation Allowance in
Determining Value?
Proposed Sec. 206.109 includes the substance of Sec. 206.104 of the
January 1997 proposed rule with only minor wording changes.
Proposed Sections 206.110 and 206.111 How Do I Determine a
Transportation Allowance Under an Arm's-Length Transportation Contract,
and How Do I Determine a Transportation Allowance Under a Non-Arm's-
Length Transportation Contract?
Proposed Secs. 206.110 and 206.111 are existing Sec. 206.105(a) and
(b) respectively, rewritten to reflect plain English, except that
existing Sec. 206.105(b)(5) is deleted as discussed in the January 1997
proposed rule preamble.
Proposed Section 206.112 What Adjustments and Transportation
Allowances Apply When I Value Oil Using Index Pricing?
Proposed Sec. 206.112 is a modified version of Sec. 206.105(c) of
the January 1997 proposed rule. Proposed Sec. 206.112 lists the various
location differentials, quality differentials, and transportation
allowances that could apply depending on your individual circumstances.
In other words, Sec. 206.112 is a ``menu'' of possible adjustments that
could apply in different circumstances. Section 206.113 then prescribes
which of the adjustments from the ``menu'' apply to specific
circumstances.
One difference from the January 1997 proposed rule is that we
eliminated the location differential between the index pricing point
and the market center. This is because under the valuation procedures
in this further supplementary proposed rule, the index pricing point
and market center would be synonymous in all cases except for the Rocky
Mountain Area. Where proposed Sec. 206.102 of this further
supplementary proposed rule does not apply in the Rocky Mountain Area
and NYMEX prices would apply, we propose at Sec. 206.112(f) to
designate Cushing, Oklahoma, as the market center for adjustment
purposes.
The other difference from the January 1997 proposed rule is that we
have added, at proposed Sec. 206.112(e), a separate adjustment to
reflect quality differences between your oil as produced at the lease
and the oil at the
[[Page 6121]]
aggregation point or market center applicable to your lease. You would
make these quality adjustments according to the pipeline quality bank
specifications and related premia or penalties that may apply in your
specific situation. If no pipeline quality bank applies to your
production, then you would not take this quality adjustment. Likewise,
if a quality adjustment is already contained in an arm's-length
exchange agreement from the lease to the market center, you would not
also claim a pipeline quality bank adjustment from the lease to the
aggregation point or market center. MMS believes this additional
adjustment would more accurately reflect actual quality adjustments
made by buyers and sellers. MMS requests comments on this change and on
the overall location/quality/transportation adjustments proposed.
Proposed Section 206.113 Which Adjustments and Transportation
Allowances May I Use When I Value Oil Using Index Pricing?
Paragraphs 206.105(c)(2) and (c)(3) of the January 1997 proposed
rule listed the specific adjustments and allowances permitted for
leases not located in California/Alaska and those in California/Alaska,
respectively. We propose to combine these paragraphs in Sec. 206.113 of
this further supplementary proposed rule. This new paragraph would
cover all situations regardless of lease location, so no geographical
breakdown of adjustments and allowances would be needed. As explained
above, Sec. 206.113 would prescribe which adjustments of the
Sec. 206.112 ``menu'' apply to your circumstances. Section 206.113 as
here proposed covers all circumstances in which index price is used for
all geographical areas. Otherwise, there are only two major differences
from the methods described in the January 1997 proposed rule. First,
you would be permitted to take a separate quality adjustment between
your lease and the associated aggregation point or market center as
discussed above.
Second, proposed Sec. 206.113(d)(2) of this further supplementary
proposed rule would address situations where you dispose of production
at the lease in exercising a non-competitive crude oil call and thus
are required to use index pricing. In such cases, you would have access
to MMS's published differentials between the market center and
aggregation point, but you may not have access to the actual cost
information from the lease to the aggregation point. In such cases,
which should be infrequent, MMS proposes to permit you to request
approval for a transportation allowance. In determining the allowance
for transportation from the lease to the aggregation point, MMS will
look to transportation costs and quality adjustments reported for other
oil production in the same field or area, or to available information
for similar transportation situations.
Proposed Sec. 206.113(a) covers situations where you transport your
oil to an MMS-recognized aggregation point, then enter into an arm's-
length exchange agreement between that point and the market center. To
arrive at the royalty value, you would adjust the index price by the
elements described in Sec. 206.112(a), (c), and (e). The first element
is the location/quality differential in your arm's-length exchange
agreement between the market center and the aggregation point for your
lease. This adjustment results in a value at the aggregation point,
recognizing that oil originating there may be of significantly
different quality from that of your oil at the lease. The second
adjustment reflects your actual transportation costs between the
aggregation point and your lease. These costs are determined under
Secs. 206.110 or 206.111 depending on whether your transportation
arrangement is arm's length or not. A third adjustment may be warranted
if the quality of your lease production differs from that of the oil
you exchanged at the aggregation point. This last adjustment would be
based on pipeline quality bank premia or penalties, but only if such
quality banks exist at the aggregation point or intermediate
commingling points before your oil reaches the aggregation point.
For example, Company A transports its production from a platform in
the Gulf of Mexico to an MMS-recognized aggregation point under an
arm's-length transportation contract for $0.50 per barrel. Company A
then enters into an arm's-length exchange agreement between the MMS-
recognized aggregation point and the market center at St. James,
Louisiana. Company A then refines the oil it receives at the market
center so that it must determine value using an index price under
Sec. 206.103. The arm's-length exchange agreement contains a location/
quality differential of $0.10 per barrel. The average of the daily mean
spot prices for St. James (the market center nearest the lease with
crude oil most similar in quality to Company A's oil) is $20.00 per
barrel for deliveries during the production month. The value of Company
A's production at the lease is $19.40 ($20.00--$0.10--$0.50) per
barrel.
Paragraph 206.113(b) addresses cases where you move your production
directly to your or your affiliate's refinery and not to an index
pricing point, and establish value based on index prices under
Sec. 206.103. In this case, for the reasons explained below, you would
deduct from the index price your actual costs of transporting
production from the lease to the refinery under Sec. 206.112(c) and any
quality adjustments determined by pipeline quality banks under
Sec. 206.112(e). The index pricing point is the one nearest the lease.
For example, a lessee or its affiliate in the Gulf of Mexico might
transport its production directly to a refinery on the eastern coast of
Texas and not to an index pricing point. It may or may not pass through
an MMS-identified aggregation point. If that production is not sold at
arm's-length, the lessee must base value on the average of the daily
mean spot prices for St. James less actual costs of transporting the
oil to the refinery and any quality adjustments from the lease to the
refinery. Likewise, if a lessee or its affiliate transports Wyoming
sour crude oil directly to its refinery in Salt Lake City, Utah, and
values the oil based on Sec. 206.103(b)(3), the lessee must base value
on the average of the daily NYMEX settled prices, less actual cost of
transporting the oil from Salt Lake City and any quality adjustments
from the lease to the refinery.
When production is moved directly to a refinery and value must be
established using an index, issues arise because the refinery generally
is not located at an index pricing point. Consequently, the lessee does
not incur actual costs to transport production to an index pricing
point, and in any event, the production is not sold at arm's-length at
that point. The principle underlying the rules and cases granting
allowances for transportation costs is that the lessee is not required
to transport production to a market remote from the lease or field at
its own expense. When the lessee sells production at a remote market,
the costs of transporting to that market are deductible from value at
that market to determine the value of the production at or near the
lease. Where there are no sales at a distant market, the question of a
transportation allowance, as that term always has been understood, does
not arise. However, because the lease and the index pricing point may
be distant from one another, there is a difference in the value of the
production between the index pricing point and the location of the
lease. The question becomes how to determine or how best to approximate
that difference in value.
[[Page 6122]]
In theory, one solution would be for MMS to try to derive what it
would cost a lessee to move production from the lease to the index
pricing point. There are, in MMS's view, several problems with such an
approach. First, it would require a burdensome information collection
from industry and require substantial information collection costs from
many parties to whom the calculation derived from the information may
never be relevant. Second, in many cases it may well not be possible to
obtain information on which to base such a calculation. MMS anticipates
that many lessees may move production directly to their refineries
without shipping the oil through MMS-recognized aggregation points. In
many instances, it is likely that no production from the lease or field
is transported to the index pricing point that applies under
Sec. 206.103. Consequently, in such cases there would be no useful data
on which such a cost derivation could be based.
Another possible solution, in theory, would be for MMS to derive a
location adjustment between the index pricing point and the refinery.
This might be possible, for example, if there are arm's-length
exchanges of significant volumes of oil between the index pricing point
and the refinery, and if the exchange agreements provide for location
adjustments that can be separated from quality adjustments. But
establishing such location adjustments on any scale again would require
a burdensome information collection effort. MMS also anticipates that
in many cases there would be no useful data from which to derive a
location adjustment.
MMS therefore believes that the best and most practical proxy
method for determining the difference in value between the lease and
the index pricing point is to use the index price as value at the
refinery, and then allow the lessee to deduct the actual costs of
moving the production from the lease to the refinery. This is not a
``transportation allowance'' as that term is commonly understood, but
rather is part of the methodology for determining the difference in
value due to the location difference between the lease and the index
pricing point. Nevertheless, it is appropriate to include this
deduction as part of the allowance ``menu'' for situations in which
index pricing is used.
MMS proposed this same method in the January 24, 1997, proposed
rule, and did not receive any suggestions for alternative methods.
Absent better alternatives, MMS believes this method is the best and
most reasonable way to calculate the differences in value due to
location when production is not actually moved from the lease to an
index pricing point.
However, if a lessee believes that applying the index price nearest
the lease to production moved directly to a refinery results in an
unreasonable value based on circumstances of the lessee's production,
Sec. 206.103(e) would allow MMS to approve an alternative method if the
lessee can demonstrate the market value at the refinery.
It would be the lessee's burden to provide adequate documentation
and evidence demonstrating the market value at the refinery. That
evidence may include, but is not limited to (1) costs of acquiring
other crude oil at or for the refinery; (2) how adjustments for
quality, location, and transportation were factored into the price paid
for the other oil; (3) the volumes acquired for the refinery; and (4)
other appropriate evidence or documentation that MMS requires. If MMS
approves a value representing market value at the refinery, there would
be no deduction for the costs of transporting the oil to the refinery
under Secs. 206.113(b) and 206.112(c). Whether any quality adjustment
would be available would depend on whether the oil passed through a
pipeline quality bank or if an arm's-length exchange agreement used to
get oil to the refinery contained a separately identifiable quality
adjustment.
Proposed Sec. 206.113(c) covers situations where you transport your
oil directly to an MMS-identified market center. To arrive at the
royalty value, you would adjust the index price by the elements
described in Sec. 206.112(d) and (e). The first element is the actual
costs of transporting production from the lease to the market center. A
second adjustment may be warranted if the quality of your lease
production differs from quality of the oil at the market center. This
last adjustment would be based on pipeline quality bank premia or
penalties, but only if such quality banks exist at the aggregation
point or intermediate commingling points before your oil reaches the
market center.
For example, Company A transports its production from a platform in
the Gulf of Mexico to St. James, Louisiana, under a non-arm's-length
transportation contract with its affiliate. The actual costs of
transporting production under Sec. 206.111 is $0.50 per barrel. The
average of the daily spot prices at St. James is $20.00 per barrel for
deliveries during the production month. The value of Company A's
production at the lease is $19.50 ($20.00--$0.50) per barrel.
Proposed paragraph (d)(1) covers situations where you cannot use
paragraphs (a), (b), or (c) of Sec. 206.113. To arrive at the royalty
value, you would adjust the index price by the elements described in
Sec. 206.112(b), (c), and (e). For example, Company A transports its
production from a lease in the Gulf of Mexico through its own pipeline
to an MMS-recognized aggregation point. Company A's actual costs of
transportation from the lease to the aggregation point are $0.10 per
barrel. Company A then enters into an exchange agreement with its
affiliate. After the exchange, Company A refines the oil so that it
must value the oil using Sec. 205.103. The MMS-published differential
from the aggregation point to the market center is $0.50 per barrel.
The average of the daily mean spot prices for St. James (the market
center nearest the lease with crude oil most similar in quality to
Company A's oil) is $20.00 per barrel for deliveries during the
production month. The value of Company A's production at the lease is
$19.40 ($20.00--$0.50--$0.10) per barrel.
MMS requests any comments you may have regarding the specific
permissible adjustments and transportation allowances under different
oil disposal situations.
Proposed Section 206.114 What if I Believe the MMS-Published Location/
Quality Differential is Unreasonable in My Circumstances?
This section would include the substance of Sec. 206.105(c)(4) of
the January 1997 proposed rule. It would provide that MMS may approve
an alternate location/quality differential if you can show that the
MMS-calculated differential under Sec. 206.112(b) of this further
supplementary proposed rule is unreasonable given your circumstances.
However, we propose to eliminate the details of filing such a request
as listed in the January 1997 proposed rule. Some of these details were
confusing and some were unnecessary because they are covered in other
parts of MMS's regulations. We believe it suffices to simply provide
you an opportunity to request an alternate differential. Please provide
us any comments you may have regarding such requests.
Note also that MMS proposes to entirely eliminate
Sec. 206.105(c)(5), (c)(6), and (c)(7) of the January 1997 proposed
rule. They referred to publications used to make index price
adjustments based on spot price differences between the index pricing
point and the market center. Since this adjustment no longer applies in
the further supplementary proposed rule, we have removed these
paragraphs.
[[Page 6123]]
Proposed Section 206.115 How Will MMS Identify Market Centers and
Aggregation Points?
Proposed Sec. 206.115 is Sec. 206.105(c)(8) of the January 1997
proposed rule with only minor wording changes. In the January 1997
proposed rule preamble, MMS listed market centers for purposes of the
rule. That list included Guernsey, Wyoming. MMS now proposes to
eliminate Guernsey as a market center for the reasons given earlier.
Also, MMS has attempted to refine and limit the aggregation points
identified in the January 1997 proposed rule to better reflect actual
locations where oil is aggregated. The current list of proposed
aggregation points is included as Attachment B to this preamble. We
note that, as this further supplementary proposed rule indicates, we
would continue to refine the list of aggregation points and associated
market centers. We would add and delete aggregation points as
experience dictates. This will help to keep the location/quality/
transportation adjustment process realistic and current.
Proposed Section 206.116 What Are My Reporting Requirements Under an
Arm's-Length Transportation Contract?
Proposed Sec. 206.116 is Sec. 206.105(c)(1) of the existing rule
rewritten in plain English.
Proposed Section 206.117 What Are My Reporting Requirements Under a
Non-Arm's-Length Transportation Contract?
Proposed Section Sec. 206.117 is Sec. 206.105(c)(2) of the existing
rule rewritten in plain English, except Sec. 206.105(c)(2)(iv) would be
deleted as described in the January 1997 proposed rule preamble.
Proposed Section 206.118 What Information Must I Provide To Support
Index Pricing Adjustments, and How Is That Information Used?
Proposed Sec. 206.118 includes the substance of Sec. 206.105(d)(3)
of the January 1997 proposed rule. This section describes information
and filing requirements for proposed Form MMS-4415. The previous
proposal stated that you must submit information on all your and your
affiliates' crude oil production, and not just information related to
Federal lease production. MMS received many comments on the form filing
burden, including comments that reporting for non-Federal lease
production should not be required. Consistent with its other attempts
to streamline the differential process, MMS proposes to limit the
information required on Form MMS-4415 to that associated with
production from Federal leases only. However, we reserve the right to
review information related to your non-Federal production under 30 CFR
part 217. We clarified this point in the revised instructions included
with Form MMS-4415, Attachment A. We have eliminated other reporting
requirements on Form MMS-4415 and revised all the related instructions
to clarify the information required.
MMS also received various comments on timing of submittal of Form
MMS-4415. Some commenters believed the information should be submitted
more often than yearly because the differential information can change
rapidly. Others believed that differential changes did not change often
and that MMS should require Form MMS-4415 submittal less frequently. On
balance, MMS proposes to maintain the submittal frequency at once a
year as originally proposed.
Also, in its written comments, one industry organization stated
that few of their members have non-competitive calls that are
exercised. It appears that most of the producers who would be required
to pay on index prices would be doing so because they have affiliates
that are physically moving or exchanging the oil to market centers. If
that is true, they would be able to use their actual differentials and
would not rely on MMS's published location differentials derived from
Form MMS-4415 data. MMS requests comments on whether this is a fair
representation and, if so, could MMS eliminate Form MMS-4415 entirely
and deal with those who don't have access to the needed data on an
exception basis?
Proposed Section 206.119 What Interest and Assessments Apply if I
Improperly Report a Transportation Allowance?
Proposed Sec. 206.119 is Sec. 206.105(d) of the existing rule
rewritten in plain English.
Proposed Section 206.120 What Reporting Adjustments Must I Make for
Transportation Allowances?
Proposed Sec. 206.120 is Sec. 206.105(e) of the existing rule
rewritten in plain English.
Proposed Section 206.121 Are Costs Allowed for Actual or Theoretical
Losses?
Proposed Sec. 206.121 is Sec. 206.105(f) of the existing rule
rewritten in plain English, except the reference to the Federal Energy
Regulatory Commission or State regulatory agency approved tariffs would
be deleted as described in the January 1997 proposed rule preamble.
Proposed Section 206.122 How Are the Royalty Quantity and Quality
Determined?
Proposed Sec. 206.122 is Sec. 206.103 of the existing rule
rewritten in plain English.
Proposed Section 206.123 How Are Operating Allowances Determined?
Proposed Sec. 206.123 is Sec. 206.106 of the existing rule
rewritten in plain English.
Proposed Change to 30 CFR 208.4(b)(2)
In the January 1997 proposed rule, MMS proposed to modify the RIK
valuation procedures to tie them directly to MMS's proposed index
pricing provisions less a location/quality differential specified in
the RIK contract. MMS has decided not to proceed with this approach.
Instead, MMS is considering establishing future RIK pricing terms
directly within the contracts it writes with RIK program participants.
MMS's goal is still to achieve pricing certainty in RIK transactions.
But because of its revised plans, MMS is dropping its proposed January
1997 change to 30 CFR 208.4(b)(2).
IV. Procedural Matters
The Regulatory Flexibility Act
The Department certifies that this rule will not have significant
economic effect on a substantial number of small entities under the
Regulatory Flexibility Act (5 U.S.C. Sec. 601 et seq.). Approximately
600 payors pay royalties to MMS on oil production from Federal lands.
The majority of these payors are considered small businesses under the
Regulatory Flexibility Act definitions. This rule will not
significantly impact a substantial number of small entities because
this rule does not add significant or costly new reporting
requirements. Only the integrated payors with either a refinery,
marketing capability, or both will be impacted. As a whole, this set of
payors is primarily made up of very large oil companies with over 500
employees. The proposed collection of information will likely also
impact a few companies with less than 500 employees (small businesses
by the Office of Management and Budget (OMB) definitions). However, if
a company is small and they engage in very few contracts where oil is
exchanged, they have less information to report. We estimate that
smaller companies (i.e., companies with less than 10 million but
greater than one million barrels of annual domestic production, which
included 3.5 Federal lessees in 1996) will each have
[[Page 6124]]
approximately 50 exchange agreements to review to identify the relevant
contracts needed for reporting under this proposed rule. Of those
contracts, we estimate that each small company will have to report on 5
exchange agreements. We estimate that the burden for a small company is
29.25 hours including 20 hours to aggregate the exchange agreement
contracts to a central location, 8 hours to sort the exchange agreement
contracts, and 1.25 additional hours to extract the relevant
information and complete Form MMS-4415 (\1/4\ hour to complete each
form). For the 35 small companies, we estimate that the burden is
1,023.75 hours. MMS believes that because of the very small number of
companies impacted and the relatively small costs to those companies of
complying with the information collection, this is not significant
action.
Unfunded Mandates Reform Act of 1995
The Department of the Interior has determined and certifies
according to the Unfunded Mandates Reform Act, 2 U.S.C. Sec. 1502 et
seq., that this rule will not impose a cost of $100 million or more in
any given year on local, tribal, or State governments, or the private
sector.
Fairness Board and National Ombudsman Program
Your comments are important. The Small Business and Agriculture
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 agencies responsiveness to small
businesses. If you wish to comment on the enforcement actions of MMS,
call 1-888-734-3247.
Executive Order 12630
The Department certifies that the rule does not represent a
governmental action capable of interference with constitutionally
protected property rights. Thus, a Takings Implication Assessment need
not be prepared under Executive Order 12630, Governmental Actions and
Interference with Constitutionally Protected Property Rights.
Executive Order 12988
The Department has certified to OMB that this proposed rule meets
the applicable civil justice reform standards provided in sections 3(a)
and 3(b)(2) of this Executive Order.
Executive Order 12866
The Office of Management and Budget has determined this rule is a
significant rule under this Executive Order 12866 section 3(f)(4). This
states a rule is considered a significant regulatory action if it
``Raises novel legal or policy issues arising out of legal mandates,
the President's priorities, or the principles set forth in this
Executive Order.'' The Department's analysis of these proposed
revisions to the oil valuation regulations indicate these changes will
not have a significant economic effect, as defined by section 3(f)(1)
of this Executive Order. However, the Executive Order 12866 regulatory
compliance and review requirements will be met and are available upon
request. MMS estimates that the economic impact of this rule will be
about $66 million. This estimate is based on a comparison of royalty
payments received from Federal onshore and offshore leases in 1996 to
what would be required under the proposed rule. The analysis was
completed for each of the three geographic divisions of the proposed
rule. Producers without refinery capacity were not included in the
analysis, as we assumed that those payors would continue to value their
production based on gross proceeds received under an arm's-length
contract. In the analysis, we compared index prices adjusted for
location and quality to prices reported on Form MMS-2014 less any
reported transported allowances to arrive at the overall net gain or
loss associated with the proposed rulemaking.
Paperwork Reduction Act
This proposed rule contains a collection of information which has
been submitted to 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, MMS invites the public and
other Federal agencies to comment on any aspect of the reporting
burden. Submit your comments to the Office of Information and
Regulatory Affairs, OMB, Attention: Desk Officer for the Department of
the Interior, Washington, D.C. 20503. Send copies of your comments to
Minerals Management Service, Royalty Management Program, Rules and
Procedures Staff, P.O. Box 25165, MS 3021, Denver, Colorado 80225-0165;
courier address is Building 85, Denver Federal Center, Denver, Colorado
80225; e-Mail address is David__G[email protected].
OMB may make a decision to approve or disapprove this collection of
information after 30 days from receipt of our request. Therefore, your
comments are best assured of being considered by OMB if OMB receives
them within that time period. However, MMS will consider all comments
received during the comment period for this notice of proposed
rulemaking.
The information collection will be on new Form MMS-4415 titled Oil
Location Differential Report. Part of the valuation of oil not sold
under arm's-length contract relies on price indices that lessees may
adjust for location/quality differences between the market center and
the aggregation point or lease. Federal lessees and their affiliates
would be required to give MMS specific information from their various
oil exchange agreements and sales contracts applicable to Federal
production. From this data MMS would calculate and publish
representative location differentials for lessees' use in reporting
royalties in various areas. This process would introduce certainty into
royalty reporting. Rules establishing the use of Form MMS-4415 to
report oil location differentials are at proposed 30 CFR 206.118.
The number of exchange agreement contracts involving aggregation
points and market centers required to be reported under this proposed
rule is considerably less than required to be reported on under the
January 24, 1997, proposed rule. While we recognize that the initial
reporting burden will still be sizable, it is reasonable to expect that
the burden in succeeding years will be less because of efficiencies
gained in the initial filing of Form MMS-4415. Our estimate is for the
initial reporting burden and is based upon review of comments from
industry from the initial, supplemental and further supplementary
proposed rulemakings, comments at public meetings and comments at the
MMS workshops held in October 1997 and consultation with MMS auditors
about their review of exchange agreement contracts that they have
examined in their recent work.
While MMS requires that only aggregation point to market center
exchange agreement contracts be reported, we anticipate that companies
will have to sort through their exchange agreement contracts before the
relevant exchange agreement contracts can be compiled and the required
information extracted and reported. Almost all Federal lessees who will
be required to file this exchange agreement contract information; that
is, exchanges between aggregation points and market centers, will have
annual total (Federal and non-Federal) domestic production in excess of
one-million barrels of crude oil; fifty-
[[Page 6125]]
nine (59) lessees had annual total domestic production in excess of
one-million barrels of crude oil in 1996.
We estimate that a large company, i.e., a company with over 30
million barrels annual domestic production (13 Federal lessees), will
have approximately 1,000 exchange agreement contracts that they will
have to review in order to identify the relevant contracts needed for
reporting purposes under this proposed rule. We estimate that a large
company will have to report on 100 exchange agreement contracts
following a review of all of the company's exchange agreement
contracts. We estimate that the burden associated with fulfilling the
information collection requirements of this proposed rule for a larger
company is 185 hours. The burden hour estimate of 185 hours includes 80
hours to aggregate the exchange agreement contracts to a central
location, 80 hours to sort the exchange agreement contracts, and 25
additional hours to extract the relevant information and complete Form
MMS-4415 (\1/4\ hour to complete each form). For 13 larger companies,
we estimate that the burden is 2,405 hours (185 hours x 13 larger
companies); using a per hour cost of $35, we estimate the cost is
$84,175.
We estimate that a mid-sized company, i.e., a company with between
10 and 30 million barrels annual domestic production (11 Federal
lessees), will have approximately 250 exchange agreement contracts that
they will have to review in order to identify the relevant exchange
contracts needed for reporting purposes under this proposed rule. We
estimate that a mid-sized company will have to report on 25 exchange
agreement contracts following a review of all of the company's exchange
agreement contracts. We estimate that the burden associated with
fulfilling the information collection requirements of this proposed
rule for a mid-sized company is 106.25 hours. The burden hour estimate
of 106.25 hours includes 60 hours to aggregate the exchange agreement
contracts to a central location, 40 hours to sort the exchange
agreement contracts, and 6.25 additional hours to extract the relevant
information and complete Form MMS-4415 (\1/4\ hour to complete each
form). For 11 mid-sized companies, we estimate that the burden is
1168.75 hours (106.25 hours x 11 mid-sized companies); using a per
hour cost of $35, we estimate the cost is $40,906.25.
We estimate that a small company, i.e., a company with less than 10
barrels annual domestic production (35 Federal lessees), will have
approximately 50 exchange agreement contracts that they will have to
review in order to identify the relevant exchange agreement contracts
needed for reporting purposes under this proposed rule. We estimate
that a small company will have to report on 5 exchange contracts
following a review of all of the company's exchange agreement
contracts. We estimate that the burden associated with fulfilling the
information collection requirements of this proposed rule for a smaller
company is 29.25 hours. The burden hour estimate of 29.25 hours
includes 20 hours to aggregate the exchange agreement contracts to a
central location, 8 hours to sort the exchange agreement contracts, and
1.25 additional hours to extract the relevant information and complete
Form MMS-4415 (\1/4\ hour to complete each form). For 35 smaller
companies, we estimate that the burden is 1023.75 hours (29.25 hours
x 35 larger companies); using a per hour cost of $35, we estimate the
cost is $35,831.25.
We estimate that the total burden for all respondents is 4,597.5
hours. We estimate that the cost to the respondents for this
information collection is $160,912.50.
In compliance with the Paperwork Reduction Act of 1995, section
3506 (c)(2)(A), we are notifying you, members of the public and
affected agencies, of this collection of information, and are inviting
your comments. Is this information collection necessary for us to
properly do our job? Have we accurately estimated the public's burden
for responding to this collection? Can we enhance the quality, utility,
and clarity of the information we collect? Can we lessen the burden of
this information collection on the respondents by using automated
collection techniques or other forms of information technology?
National Environmental Policy Act of 1969
We have determined that this rulemaking is not a major Federal
action significantly affecting the quality of the human environment,
and a detailed statement under section 102(2)(C) of the National
Environmental Policy Act of 1969 (42 U.S.C. Sec. 4332(2)(C)) is not
required.
V. Request for Comments
You should submit written comments, suggestions, or objections
regarding this proposal to the location identified in the ADDRESSES
section of this notice. You must submit your comments on or before the
date identified in the DATES section of this notice.
List of Subjects 30 CFR Parts 206 and 208
Coal, Continental shelf, Geothermal energy, Government contracts,
Indians-lands, Mineral royalties, Natural gas, Petroleum, Public
lands--mineral resources, Reporting and recordkeeping requirements.
Dated: December 29, 1997.
Bob Armstrong,
Assistant Secretary--Land and Minerals Management.
For the reasons given in the preamble, MMS proposes to amend
subpart C of part 206 in Title 30 of the Code of Federal Regulations as
follows:
PART 206--PRODUCT VALUATION
Subpart C--Federal Oil
206.100 What is the purpose of this subpart?
206.101 Definitions.
206.102 How do I calculate royalty value for oil that I or my
affiliate sell under an arm's-length contract?
206.103 How do I value oil that I cannot value under Sec. 206.102?
206.104 What index price publications are acceptable to MMS?
206.105 What records must I keep to support my calculations of
value under this subpart?
206.106 What are my responsibilities to place production into
marketable condition and to market production?
206.107 What valuation guidance can MMS give me?
206.108 Does MMS protect information I provide?
206.109 When may I take a transportation allowance in determining
value?
206.110 How do I determine a transportation allowance under an
arm's-length transportation contract?
206.111 How do I determine a transportation allowance under a non-
arm's-length transportation arrangement?
206.112 What adjustments and transportation allowances could apply
when I value oil using index pricing?
206.113 Which adjustments and transportation allowances may I use
when I value oil using index pricing?
206.114 What if I believe the MMS-published location/quality
differential is unreasonable in my circumstances?
206.115 How will MMS identify market centers and aggregation
points?
206.116 What are my reporting requirements under an arm's-length
transportation contract?
206.117 What are my reporting requirements under a non-arm's-length
transportation contract?
206.118 What information must I provide to support index pricing
adjustments, and how is that information used?
206.119 What interest and assessments apply if I improperly report
a transportation allowance?
206.120 What reporting adjustments must I make for transportation
allowances?
[[Page 6126]]
206.121 Are costs allowed for actual or theoretical losses?
206.122 How are the royalty quantity and quality determined?
206.123 How are operating allowances determined?
Authority: 5 U.S.C. 301 et seq.; 25 U.S.C. 396 et seq., 396a et
seq., 2101 et seq.; 30 U.S.C. 181 et seq., 351 et seq., 1001 et
seq., 1701 et seq.; 31 U.S.C. 9701, 43 U.S.C. 1301 et seq., 1331 et
seq., and 1801 et seq.
Sec. 206.100 What is the purpose of this subpart?
(a) This subpart applies to all oil produced from Federal oil and
gas leases onshore and on the Outer Continental Shelf (OCS). It
explains how you as a lessee must calculate the value of production for
royalty purposes consistent with the mineral leasing laws, other
applicable laws, and lease terms. If you are a designee and if you
dispose of production on behalf of a lessee, the terms ``you'' and
``your'' in this subpart refer to you. If you are a designee and only
report for a lessee, and do not dispose of the lessee's production,
references to ``you'' and ``your'' in this subpart refer to the lessee
and not the designee. Accordingly, you as a designee must determine and
report royalty value for the lessee's oil by applying the rules in this
subpart to the lessee's disposition of its oil.
(b) This subpart does not apply in three situations. If the
regulations in this subpart are inconsistent with a Federal statute, a
settlement agreement between the United States and a lessee resulting
from administrative or judicial litigation, or an express provision of
an oil and gas lease subject to this subpart, then the statute,
settlement agreement, or lease provision will govern to the extent of
the inconsistency.
(c) MMS may audit and adjust all royalty payments.
Sec. 206.101 Definitions.
The following definitions apply to this subpart:
Affiliate means a person who owns, is owned by, or is under common
ownership with another person to the extent of 10 percent or more of
the voting securities of an entity, interest in a partnership or joint
venture, or other forms of ownership. MMS may require the lessee to
certify the percentage of ownership. Aside from the percentage
ownership criteria, relatives, either by blood or by marriage, are
affiliates.
Aggregation point means a central point where production is
aggregated for shipment to market centers or refineries. It includes,
but is not limited to, blending and storage facilities and connections
where pipelines join. Pipeline terminations at refining centers also
are classified as aggregation points. MMS periodically will publish in
the Federal Register a list of aggregation points and associated market
centers.
Area means a geographic region at least as large as the limits of
an oil field, in which oil has similar quality, economic, and legal
characteristics.
Arm's-length contract means a contract or agreement between
independent persons who are not affiliates and who have opposing
economic interests regarding that contract. To be considered arm's
length for any production month, a contract must satisfy this
definition for that month, as well as when the contract was executed.
Audit means a review, conducted under generally accepted accounting
and auditing standards, of royalty payment compliance activities of
lessees, designees or other persons who pay royalties, rents, or
bonuses on Federal leases.
BLM means the Bureau of Land Management of the Department of the
Interior.
Competitive crude oil call means a crude oil call that contains a
clause basing the price on what other parties are willing to
competitively bid to purchase the production.
Condensate means liquid hydrocarbons (normally exceeding 40 degrees
of API gravity) recovered at the surface without processing. Condensate
is the mixture of liquid hydrocarbons resulting from condensation of
petroleum hydrocarbons existing initially in a gaseous phase in an
underground reservoir.
Contract means any oral or written agreement, including amendments
or revisions, between two or more persons, that is enforceable by law
and that with due consideration creates an obligation.
Crude oil call means the right of one person to buy, at its option,
all or a part of the second person's oil production from an oil and gas
property. This right generally arises as a condition of the sale or
farmout of that property from the first person to the second, or as a
result of other transactions between them. The price basis may be
specified when the property is sold or farmed out.
Designee means the person the lessee designates to report and pay
the lessee's royalties for a lease.
Exchange agreement means an agreement where one person agrees to
deliver oil to another person at a specified location in exchange for
oil deliveries at another location. Exchange agreements may or may not
specify prices for the oil involved. They frequently specify dollar
amounts reflecting location, quality, or other differentials. Exchange
agreements include buy/sell agreements, which specify prices to be paid
at each exchange point and may appear to be two separate sales within
the same agreement.
Field means a geographic region situated over one or more
subsurface oil and gas reservoirs and encompassing at least the
outermost boundaries of all oil and gas accumulations known within
those reservoirs, vertically projected to the land surface. State oil
and gas regulatory agencies usually name onshore fields and designate
their official boundaries. MMS names and designates boundaries of OCS
fields.
Gathering means the movement of lease production to a central
accumulation or treatment point on the lease, unit, or communitized
area, or to a central accumulation or treatment point off the lease,
unit, or communitized area that BLM or MMS approves for onshore and
offshore leases, respectively.
Gross proceeds means the total monies and other consideration
accruing for the disposition of oil produced. Gross proceeds include,
but are not limited to, the following examples:
(1) Payments for services such as dehydration, marketing,
measurement, or gathering which the lessee must perform at no cost to
the Federal Government;
(2) The value of services, such as salt water disposal, that the
producer normally performs but that the buyer performs on the
producer's behalf;
(3) Reimbursements for harboring or terminaling fees;
(4) Tax reimbursements, even though the Federal royalty interest
may be exempt from taxation;
(5) Payments made to reduce or buy down the purchase price of oil
to be produced in later periods, by allocating such payments over the
production whose price the payment reduces and including the allocated
amounts as proceeds for the production as it occurs; and
(6) Monies and all other consideration to which a seller is
contractually or legally entitled, but does not seek to collect through
reasonable efforts.
Index pricing means using NYMEX futures prices, Alaska North Slope
(ANS) crude oil spot prices, or other appropriate crude oil spot prices
for royalty valuation.
Index pricing point means the physical location where an index
price is established in an MMS-approved publication.
Lease means any contract, profit-share arrangement, joint venture,
or other
[[Page 6127]]
agreement issued or approved by the United States under a mineral
leasing law that authorizes exploration for, development or extraction
of, or removal of oil or gas products--or the land area covered by that
authorization, whichever the context requires.
Lessee means any person to whom the United States issues an oil and
gas lease, an assignee of all or a part of the record title interest,
or any person to whom operating rights in a lease have been assigned.
Load oil means any oil used in the operation of oil or gas wells
for wellbore stimulation, workover, chemical treatment, or production
purposes. It does not include oil used at the surface to place lease
production in marketable condition.
Location differential means the value difference for oil at two
different points.
Market center means a major point MMS recognizes for oil sales,
refining, or transshipment. Market centers generally are locations
where MMS-approved publications publish oil spot prices.
Marketable condition means oil sufficiently free from impurities
and otherwise in a condition a purchaser will accept under a sales
contract typical for the field or area.
Minimum royalty means that minimum amount of annual royalty the
lessee must pay as specified in the lease or in applicable leasing
regulations.
MMS-approved publication means a publication MMS approves for
determining NYMEX prices, ANS or other spot prices, or location
differentials.
Netting means reducing the reported sales value to account for
transportation instead of reporting a transportation allowance as a
separate line on Form MMS-2014.
Non-competitive crude oil call means a crude oil call that does not
contain a clause basing the price on what other parties are willing to
competitively bid to purchase the production.
NYMEX means the New York Mercantile Exchange.
Oil means a mixture of hydrocarbons that existed in the liquid
phase in natural underground reservoirs, remains liquid at atmospheric
pressure after passing through surface separating facilities, and is
marketed or used as a liquid. Condensate recovered in lease separators
or field facilities is considered oil.
Outer Continental Shelf (OCS) means all submerged lands lying
seaward and outside of the area of lands beneath navigable waters as
defined in section 2 of the Submerged Lands Act (43 U.S.C. 1301) and of
which the subsoil and seabed appertain to the United States and are
subject to its jurisdiction and control.
Person means any individual, firm, corporation, association,
partnership, consortium, or joint venture (when established as a
separate entity).
Prompt month means the nearest month for which NYMEX futures are
traded on any given day. Futures trading terminates at the close of
business on the third business day before the 25th calendar day of the
month preceding the delivery month. For example, if November 25 is a
Tuesday, futures trading for the prompt month of December would end
November 20, the third-previous business day. Trading for the December
prompt month would begin October 23, the day following the end of
trading for the November prompt month.
Quality differential means the value difference between two oils
due to differences in their API gravity, sulfur content, viscosity,
metals content, and other quality factors.
Rocky Mountain Area means the States of Colorado, Montana, North
Dakota, South Dakota, Utah, and Wyoming.
Sale means a contract between two persons where:
(1) The seller unconditionally transfers title to the oil to the
buyer. The seller may not retain any related rights such as the right
to buy back similar quantities of oil from the buyer elsewhere;
(2) The buyer pays money or other consideration for the oil; and
(3) The parties' intent is for a sale of the oil to occur.
Spot price means the price under a spot sales contract where:
(1) A seller agrees to sell to a buyer a specified amount of oil at
a specified price over a specified period of short duration;
(2) No cancellation notice is required to terminate the sales
agreement; and
(3) There is no obligation or implied intent to continue to sell in
subsequent periods.
Tendering program means a company offer of a portion of its crude
oil production from a field, area, or other geographical/physical unit
for competitive bidding.
Transportation allowance means a deduction in determining royalty
value for the reasonable, actual costs of moving oil to a point of sale
or delivery off the lease, unit area, or communitized area. The
transportation allowance does not include gathering costs.
Sec. 206.102 How do I calculate royalty value for oil that I or my
affiliate sell under an arm's-length contract?
(a) The value of oil under paragraphs (a)(1) through (4) of this
section is the gross proceeds accruing to the seller under the arm's-
length contract, less applicable allowances determined under this
subpart. See paragraph (c) of this section for exceptions. Use this
paragraph to value oil that:
(1) You sell under an arm's-length sales contract;
(2) You sell or transfer to your affiliate and that affiliate, or
another affiliate, then sells the oil under an arm's-length contract;
(3) You sell or transfer to another person under a non-arm's-length
contract and that person, or an affiliate of that person, sells the oil
under an arm's-length contract; or
(4) You sell in the exercise of a competitive crude oil call.
(b) If oil valued under paragraphs (a)(2) or (a)(3) of this section
is sold under multiple arm's-length contracts, the value of the oil is
the volume-weighted average of the values established under this
section for each contract.
(c) This paragraph contains exceptions to the valuation rule in
paragraph (a) of this section. Apply these exceptions on an individual
contract basis.
(1) If MMS determines that any arm's-length sales contract does not
reflect the total consideration actually transferred either directly or
indirectly from the buyer to the seller, MMS may require that you value
the oil sold under that contract either under Sec. 206.103 or at the
total consideration received.
(2) You must value the oil under Sec. 206.103 if MMS determines
that the value under paragraph (a) of this section does not reflect the
reasonable value of the production due to either:
(i) Misconduct by or between the parties to the arm's-length
contract; or
(ii) Breach of your duty to market the oil for the mutual benefit
of yourself and the lessor.
(3) You must use Sec. 206.103 to value oil disposed of under an
exchange agreement. However, if you enter into one or more arm's-length
exchange agreements, and following those exchanges you dispose of the
oil in a transaction to which paragraph (a) of this section applies,
then you must value the oil under paragraph (a) of this section. Adjust
that value for any location or quality differential or other
adjustments you received or paid under the arm's-length exchange
agreement(s). But if MMS determines that any arm's-length exchange
agreement does not
[[Page 6128]]
reflect reasonable location or quality differentials, MMS may require
you to value the oil under Sec. 206.103.
(4) You must use Sec. 206.103 to value oil disposed of in the
exercise of a non-competitive crude oil call.
(d) What else must I do if I value oil under paragraph (a)?
(1) You must be able to demonstrate that a contract or exchange
agreement is an arm's-length contract or exchange agreement.
(2) MMS may require you to certify that arm's-length contract
provisions include all of the consideration the buyer must pay, either
directly or indirectly, for the oil.
(3) You must base value on the highest price the seller can receive
through legally enforceable claims under the contract. If the seller
fails to take proper or timely action to receive prices or benefits it
is entitled to, you must pay royalty at a value based upon that
obtainable price or benefit. If the seller makes timely application for
a price increase or benefit allowed under the contract but the
purchaser refuses, and the seller takes reasonable documented measures
to force purchaser compliance, you will owe no additional royalties
unless or until the seller receives monies or consideration resulting
from the price increase or additional benefits. This paragraph will not
permit you to avoid your royalty payment obligation where a purchaser
fails to pay, pays only in part, or pays late. Any contract revisions
or amendments that reduce prices or benefits to which the seller is
entitled must be in writing and signed by all parties to the arm's-
length contract.
Sec. 206.103 How do I value oil that I cannot value under
Sec. 206.102?
This section explains how to value oil that you may not value under
Sec. 206.102.
(a) Production from leases in California or Alaska. Value is the
average of the daily mean Alaska North Slope (ANS) spot prices
published in any MMS-approved publication during the calendar month
preceding the production month. To calculate the daily mean spot price,
average the daily high and low prices for the month in the selected
publication. Use only the days and corresponding spot prices for which
such prices are published. You must adjust the value for applicable
location and quality differentials, and you may adjust it for
transportation costs, under Secs. 206.112 and 206.113 of this subpart.
(b) Production from leases in the Rocky Mountain Area. Value your
oil under the first applicable of the following paragraphs:
(1) If you have an MMS-approved tendering program, the value of
production from leases in the area the tendering program covers is the
highest price bid for tendered volumes. You must offer and sell at
least 33\1/3\ percent of your production from both Federal and non-
Federal leases in that area under your tendering program. You also 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. MMS will provide additional criteria for approval of a
tendering program in its ``Oil and Gas Payor Handbook.''
(2) Value is the volume-weighted average gross proceeds accruing to
the seller under you or your affiliates' arm's-length contracts for the
purchase or sale of production from the field or area during the
production month. 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.
(3) Value is the average of the daily NYMEX futures settle prices
at Cushing, Oklahoma, for the light sweet crude oil contract for the
prompt month that is in effect on the first day of the month preceding
the production month. Use only the days and corresponding NYMEX prices
for which such prices are published. You must adjust the value for
applicable location and quality differentials, and you may adjust it
for transportation costs, under Secs. 206.112 and 206.113 of this
subpart.
(4) If you demonstrate to MMS's satisfaction that paragraphs (b)(1)
through (b)(3) of this section result in an unreasonable value for your
production as a result of circumstances regarding that production, the
MMS Director may establish an alternative valuation method.
(c) Production from leases not located in California, Alaska, or
the Rocky Mountain Area. Value is the average of the daily mean spot
prices--
(1) For the market center nearest your lease where spot prices are
published in an MMS-approved publication;
(2) For the crude oil most similar in quality to your oil (for
example, at the St. James, Louisiana, market center, spot prices are
published for both Light Louisiana Sweet and Eugene Island crude oils.
Their quality specifications differ significantly); and
(3) For deliveries during the production month. Calculate the daily
mean spot price by averaging the daily high and low prices for the
month in the selected publication. Use only the days and corresponding
spot prices for which such prices are published. You must adjust the
value for applicable location and quality differentials, and you may
adjust it for transportation costs, under Secs. 206.112 and 206.113.
(d) If MMS determines that any of the index prices referenced in
paragraphs (a), (b), and (c) of this section are unavailable or no
longer represent reasonable royalty value, in any particular case, MMS
may establish reasonable royalty value based on other relevant matters.
(e) What if I transport my oil to my refinery and believe that use
of a particular index price is unreasonable?
(1) If you transport your oil directly to your or your affiliate's
refinery, or exchange your oil at arm's length for oil delivered to
your or your affiliate's refinery, and if value is established under
this section at an index price, and if you believe that use of the
index price is unreasonable, you may apply to the MMS Director for
approval to use a value representing the market at the refinery.
(2) You must provide adequate documentation and evidence
demonstrating the market value at the refinery. That evidence may
include, but is not limited to:
(i) Costs of acquiring other crude oil at or for the refinery;
(ii) How adjustments for quality, location, and transportation were
factored into the price paid for other oil;
(iii) Volumes acquired for and refined at the refinery; and
(iv) Any other appropriate evidence or documentation that MMS
requires.
(3) If the MMS Director approves a value representing market value
at the refinery, you may not take an allowance against that value under
Secs. 206.112(c) and 206.113(b).
Sec. 206.104 What index price 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:
(1) Publications buyers and sellers frequently use;
(2) Publications frequently mentioned in purchase or sales
contracts;
(3) Publications that use adequate survey techniques, including
development of spot price estimates based on daily surveys of buyers
and sellers of ANS and other crude oil; and
(4) Publications independent from MMS, other lessors, and lessees.
(b) Any publication may petition MMS to be added to the list of
acceptable publications.
(c) MMS will reference the tables you must use in the publications
to determine the associated index prices.
[[Page 6129]]
Sec. 206.105 What records must I keep to support my calculations of
value under this subpart?
If you determine the value of your oil under this subpart, you must
retain all data relevant to the determination of royalty value. You
must be able to show how you calculated the value you reported,
including all adjustments for location, quality, and transportation,
and how you complied with these rules. Recordkeeping requirements are
found at parts 207 and 217 of this title. MMS may review and audit such
data, and MMS will direct you to use a different value if it determines
that the reported value is inconsistent with the requirements of this
subpart.
Sec. 206.106 What are my responsibilities to place production into
marketable condition and to market production?
You must place oil in marketable condition and market the oil for
the mutual benefit of the lessee and the lessor at no cost to the
Federal Government unless otherwise provided in the lease agreement. If
you use gross proceeds under an arm's-length contract in determining
value, you must increase those gross proceeds to the extent that the
purchaser, or any other person, provides certain services that the
seller normally would be responsible to perform to place the oil in
marketable condition or to market the oil.
Sec. 206.107 What valuation guidance can MMS give me?
You may ask MMS for guidance in determining value. You may propose
a valuation method to MMS. Submit all available data related to your
proposal and any additional information MMS deems necessary. MMS will
promptly review your proposal and provide you with a non-binding
determination of the guidance you request.
Sec. 206.108 Does MMS protect information I provide?
Certain information you submit to MMS regarding valuation of oil,
including transportation allowances, may be exempt from disclosure. To
the extent applicable laws and regulations permit, MMS will keep
confidential any data you submit that is privileged, confidential, or
otherwise exempt from disclosure. All requests for information must be
submitted under the Freedom of Information Act regulations of the
Department of the Interior at 43 CFR part 2.
Sec. 206.109 When may I take a transportation allowance in determining
value?
(a) What transportation allowances are permitted when I value
production based on gross proceeds? This paragraph applies when you
value oil under Sec. 206.102 based on gross proceeds from a sale at a
point off the lease, unit, or communitized area where the oil is
produced, and the movement to the sales point is not gathering. MMS
will allow a deduction for the reasonable, actual costs to transport
oil from the lease to the point off the lease under Secs. 206.110 or
206.111, as applicable. For offshore leases, you may take a
transportation allowance for your reasonable, actual costs to transport
oil taken as royalty-in-kind (RIK) to the delivery point specified in
the contract between the RIK oil purchaser and the Federal Government.
However, for onshore leases, you may not take a transportation
allowance for transporting oil taken as RIK.
(b) What transportation allowances and other adjustments apply when
I value production based on index pricing? If you value oil using an
index price under Sec. 206.103, MMS will allow a deduction for certain
costs associated with transporting oil as provided under Secs. 206.112
and 206.113.
(c) Are there limits on my transportation allowance?
(1) Except as provided in paragraph (c)(2) of this section, your
transportation allowance may not exceed 50 percent of the value of the
oil as determined under this subpart. You may not use transportation
costs incurred to move a particular volume of production to reduce
royalties owed on production for which those costs were not incurred.
(2) You may ask MMS to approve a transportation allowance in excess
of the limitation in paragraph (c)(1) of this section. You must
demonstrate that the transportation costs incurred were reasonable,
actual, and necessary. Your application for exception (using Form MMS-
4393, Request to Exceed Regulatory Allowance Limitation) must contain
all relevant and supporting documentation necessary for MMS to make a
non-binding determination. You may never reduce the royalty value of
any production to zero.
(d) Must I allocate transportation costs? You must allocate
transportation costs among all products produced and transported as
provided in Secs. 206.110 and 206.111. You must express transportation
allowances for oil as dollars per barrel.
(e) What additional payments may I be liable for? If MMS determines
that you took an excessive transportation allowance, then you must pay
any additional royalties due, plus interest under 30 CFR 218.54. You
also could be entitled to a credit with interest under applicable rules
if you understated your transportation allowance. If you take a
deduction for transportation on Form MMS-2014 by improperly netting the
allowance against the sales value of the oil instead of reporting the
allowance as a separate line item, MMS may assess you an amount under
Sec. 206.119.
Sec. 206.110 How do I determine a transportation allowance under an
arm's-length transportation contract?
(a) If you or your affiliate incur transportation costs under an
arm's-length transportation contract, you may claim a transportation
allowance for the reasonable, actual costs incurred for transporting
oil under that contract, except as provided in paragraphs (a)(1) and
(a)(2) of this section. You must be able to demonstrate that your
contract is arm's length. You do not need MMS approval before reporting
a transportation allowance for costs incurred under an arm's-length
contract.
(1) If MMS determines that the contract reflects more than the
consideration actually transferred either directly or indirectly from
you or your affiliate to the transporter for the transportation, MMS
may require that you calculate the transportation allowance under
Sec. 206.111.
(2) If MMS determines that the consideration paid under an arm's-
length transportation contract does not reflect the reasonable value of
the transportation due to either:
(i) Misconduct by or between the parties to the arm's-length
contract; or
(ii) Breach of your duty to market the oil for the mutual benefit
of yourself and the lessor, then you must calculate the transportation
allowance under Sec. 206.111.
(b)(1) If your arm's-length transportation contract includes more
than one liquid product, and the transportation costs attributable to
each product cannot be determined from the contract, then you must
allocate the total transportation costs in a consistent and equitable
manner to each of the liquid products transported in the same
proportion as the ratio of the volume of each product (excluding waste
products which have no value) to the volume of all liquid products
(excluding waste products which have no value). You may not claim an
allowance for the costs of transporting lease production which is not
royalty-bearing without MMS approval except as provided in this
section.
(2) You may propose to MMS a cost allocation method on the basis of
the values of the products transported. MMS will approve the method
unless it is not consistent with the purposes of the regulations in
this subpart.
[[Page 6130]]
(c) If your arm's-length transportation contract includes both
gaseous and liquid products, and the transportation costs attributable
to each product cannot be determined from the contract, you must
propose an allocation procedure to MMS. You may use your proposed
procedure to calculate a transportation allowance until MMS accepts
your cost allocation. You must submit your initial proposal, including
all available data, within 3 months after the last day of the month for
which you claim a transportation allowance.
(d) If your payments for transportation under an arm's-length
contract are not on a dollar-per-unit basis, you must convert whatever
consideration is paid to a dollar value equivalent.
(e) If your arm's-length sales contract includes a provision
reducing the contract price by a transportation factor, MMS will not
consider the transportation factor to be a transportation allowance.
You may use the transportation factor in determining your gross
proceeds for the sale of the product. You must obtain MMS approval
before claiming a transportation factor in excess of 50 percent of the
base price of the product.
Sec. 206.111 How do I determine a transportation allowance under a
non-arm's-length transportation arrangement?
(a) If you or your affiliate have a non-arm's-length transportation
contract or no contract, including those situations where you or your
affiliate perform your own transportation services, calculate your
transportation allowance based on the reasonable, actual costs provided
in this section.
(b) Base your transportation allowance for non-arm's-length or no-
contract situations on your or your affiliate's actual costs for
transportation during the reporting period, including operating and
maintenance expenses, overhead, and either:
(1) Depreciation and a return on undepreciated capital investment
under paragraph (b)(4)(i) of this section, or
(2) A cost equal to the initial capital investment in the
transportation system multiplied by a rate of return under paragraph
(b)(4)(ii) of this section.
(c) Allowable capital costs are generally those for depreciable
fixed assets (including costs of delivery and installation of capital
equipment) which are an integral part of the transportation system.
(1) Allowable operating expenses include:
(i) Operations supervision and engineering; operations labor;
(ii) Fuel;
(iii) Utilities;
(iv) Materials;
(v) Ad valorem property taxes;
(vi) Rent;
(vii) Supplies; and
(viii) Any other directly allocable and attributable operating
expense which you can document.
(2) Allowable maintenance expenses include:
(i) Maintenance of the transportation system;
(ii) Maintenance of equipment;
(iii) Maintenance labor; and
(iv) Other directly allocable and attributable maintenance expenses
which you can document.
(3) Overhead directly attributable and allocable to the operation
and maintenance of the transportation system is an allowable expense.
State and Federal income taxes and severance taxes and other fees,
including royalties, are not allowable expenses.
(4) Use either depreciation or a return on depreciable capital
investment. After you have elected to use either method for a
transportation system, you may not later elect to change to the other
alternative without MMS approval.
(i) To compute depreciation, you may elect to use either a
straight-line depreciation method based on the life of equipment or on
the life of the reserves which the transportation system services, or a
unit-of-production method. After you make an election, you may not
change methods without MMS approval. A change in ownership of a
transportation system will not alter the depreciation schedule you or
your affiliate established for purposes of the allowance calculation.
With or without a change in ownership, you may only depreciate a
transportation system once. You may not depreciate equipment below a
reasonable salvage value.
(ii) For transportation facilities first placed in service after
March 1, 1988, you may use as a cost an amount equal to the initial
capital investment in the transportation system multiplied by the rate
of return under paragraph (5) of this section. You may not claim an
allowance for depreciation.
(5) The rate of return is the industrial rate for Standard and
Poor's BBB rating. Use the monthly average rate published in ``Standard
and Poor's Bond Guide'' for the first month of the reporting period for
which the allowance applies. Calculate the rate at the beginning of
each subsequent transportation allowance reporting period.
(d)(1) Calculate the deduction for transportation costs based on
your or your affiliate's cost of transporting each product through each
individual transportation system. Where more than one liquid product is
transported, allocate costs in a consistent and equitable manner to
each of the liquid products transported in the same proportion as the
ratio of the volume of each liquid product (excluding waste products
which have no value) to the volume of all liquid products (excluding
waste products which have no value). You may not take an allowance for
transporting lease production which is not royalty-bearing without MMS
approval, except as provided in this paragraph.
(2) You may propose to MMS a cost allocation method on the basis of
the values of the products transported. MMS will approve the method if
it is consistent with the purposes of the regulations in this subpart.
(e) Where both gaseous and liquid products are transported through
the same transportation system, you must propose a cost allocation
procedure to MMS. You may use your proposed procedure to calculate a
transportation allowance until MMS accepts your cost allocation. You
must submit your initial proposal, including all available data, within
3 months after the last day of the month for which you request a
transportation allowance.
Sec. 206.112 What adjustments and transportation allowances could
apply when I value oil using index pricing?
When you use index pricing to calculate the value of production
under Sec. 206.103, you must adjust the index price for the location
and quality differentials and you may adjust it for certain
transportation costs, as prescribed in this section and Sec. 206.113.
This section describes the different adjustments and transportation
allowances that could apply.
Section 206.113 specifies which of these adjustments and allowances
apply to you depending upon how you dispose of your oil. These
adjustments and transportation allowances are as follows:
(a) A location/quality differential determined from your arm's-
length exchange agreement that reflects the difference in value of
crude oil between the aggregation point and the market center, or
between your lease and the market center.
(b)(1) An MMS-specified location/quality differential that reflects
the difference in value of crude oil between the aggregation point and
the market center.
(2) MMS will publish annually a series of differentials applicable
to various aggregation points and market centers based on data MMS
collects on Form MMS-4415. MMS will calculate each differential using a
volume-
[[Page 6131]]
weighted average of the differentials reported on Form MMS-4415 for
similar quality crudes for the aggregation point-market center pair for
the previous reporting year. MMS may exclude apparent anomalous
differentials from that calculation. MMS will publish separate
differentials for different crude oil qualities that are identified
separately on Form MMS-4415 (for example, sweet versus sour or varying
gravity ranges).
(3) MMS will publish these differentials in the Federal Register by
[the effective date of the final regulation] and by January 31 of all
subsequent years. Use the MMS-published differential to report the
value of production occurring during the calendar year.
(c) Actual transportation costs between the aggregation point and
the lease determined under Sec. 206.110 or 206.111.
(d) Actual transportation costs between the market center and the
lease determined under Sec. 206.110 or 206.111.
(e) Quality adjustments based on premia or penalties determined by
pipeline quality bank specifications at intermediate commingling
points, at the aggregation point, or at the market center that applies
to your lease.
(f) For purposes of this section and Sec. 206.113, the term market
center means Cushing, Oklahoma, when determining location/quality
differentials and transportation allowances for production from leases
in the Rocky Mountain Area.
Sec. 206.113 Which adjustments and transportation allowances may I use
when I value oil using index pricing?
(a) If you dispose of your production under an arm's-length
exchange agreement, use Sec. 206.112 (a), (c), and (e) to determine
your adjustments and transportation allowances. For non-arm's-length
exchange agreements, use paragraph (d) of this section.
(b) If you move lease production directly to an alternate disposal
point (for example, your refinery), use Sec. 206.112 (c) and (e) to
determine your actual costs of transportation and to adjust for
quality. Treat the alternate disposal point as the aggregation point to
apply Sec. 206.112(c).
(c) If you move your oil directly to a MMS-identified market
center, use Sec. 206.112 (d) and (e) to determine your actual costs of
transportation and to adjust for quality.
(d)(1) If you cannot use paragraph (a), (b), or (c) of this
section, use Sec. 206.112 (b), (c), and (e) to determine your location/
quality adjustments and transportation allowances, except as provided
in paragraph (d)(2) of this section.
(2) If you dispose of your production at the lease in the exercise
of a non-competitive crude oil call, and if you cannot obtain
information regarding the actual costs of transporting oil from the
lease to the aggregation point, or pipeline quality bank specifications
necessary to apply Sec. 206.112 (c) and (e), you must request approval
from MMS for any transportation allowance.
Sec. 206.114 What if I believe the MMS-published location/quality
differential is unreasonable in my circumstances?
If you can demonstrate to MMS that the MMS-calculated differential
under Sec. 206.112(b) is unreasonable based on the circumstances of
your production, MMS may approve an alternative location/quality
differential.
Sec. 206.115 How will MMS identify market centers and aggregation
points?
MMS periodically will publish in the Federal Register a list of
aggregation points and the associated market centers. MMS will monitor
market activity and, if necessary, add to or modify the list of market
centers and aggregation points and will publish such modifications in
the Federal Register. MMS will consider the following factors and
conditions in specifying market centers and aggregation points:
(a) Points where MMS-approved publications publish prices useful
for index purposes;
(b) Markets served;
(c) Pipeline and other transportation linkage;
(d) Input from industry and others knowledgeable in crude oil
marketing and transportation;
(e) Simplification; and
(f) Other relevant matters.
Sec. 206.116 What are my reporting requirements under an arm's-length
transportation contract?
You or your affiliate must use a separate line entry on Form MMS-
2014 to notify MMS of an allowance based on transportation costs you or
your affiliate incur. MMS may require you or your affiliate to submit
arm's-length transportation contracts, production agreements, operating
agreements, and related documents.
Sec. 206.117 What are my reporting requirements under a non-arm's-
length transportation contract?
You or your affiliate must use a separate line entry on Form MMS-
2014 to notify MMS of an allowance based on transportation costs you or
your affiliate incur.
(a) For new transportation facilities or arrangements, base your
initial deduction on estimates of allowable oil transportation costs
for the applicable period. Use the most recently available operations
data for the transportation system or, if such data are not available,
use estimates based on data for similar transportation systems.
(b) MMS may require you or your affiliate to submit all data used
to calculate the allowance deduction.
Sec. 206.118 What information must I provide to support index pricing
adjustments, and how is that information used?
You must submit information on Form MMS-4415 related to all your
and your affiliates' crude oil production from Federal leases. Provide
information regarding differentials between MMS-defined market centers
and aggregation points according to the instructions provided with Form
MMS-4415. All Federal lessees (or their affiliates, as appropriate)
must initially submit Form MMS-4415 no later than 2 months after the
effective date of this reporting requirement, and then by October 31 of
the year this regulation takes effect and by October 31 of each
succeeding year.
Sec. 206.119 What interest and assessments apply if I improperly
report a transportation allowance?
(a) If you or your affiliate net a transportation allowance against
the royalty value on Form MMS-2014, you will be assessed an amount up
to 10 percent of the netted allowance, not to exceed $250 per lease
selling arrangement per sales period.
(b) If you or your affiliate deduct a transportation allowance on
Form MMS-2014 that exceeds 50 percent of the value of the oil
transported without obtaining MMS's prior approval under Sec. 206.109,
you must pay interest on the excess allowance amount taken from the
date that amount is taken to the date you or your affiliate file an
exception request MMS approves.
(c) If you or your affiliate report an erroneous or excessive
transportation allowance resulting in an underpayment of royalties, you
must pay the additional royalties plus interest under 30 CFR 218.54.
Sec. 206.120 What reporting adjustments must I make for transportation
allowances?
If your or your affiliate's actual transportation allowance is less
than the amount you claimed on Form MMS-2014 for each month during the
allowance reporting period, you must pay additional royalties plus
interest computed under 30 CFR 218.54 from the beginning of the
allowance reporting
[[Page 6132]]
period when you took the deduction to the date you repay the
difference. If the actual transportation allowance is greater than the
amount you claimed on Form MMS-2014 for each month during the allowance
form reporting period, you are entitled to a credit plus interest under
applicable rules.
Sec. 206.121 Are costs allowed for actual or theoretical losses?
For other than arm's-length contracts, you are not allowed a
deduction for oil transportation which results from payments (either
volumetric or for value) for actual or theoretical losses.
Sec. 206.122 How are royalty quantity and quality determined?
(a)(1) Compute royalties based on the quantity and quality of oil
as measured at the point of settlement approved by BLM for onshore
leases.
(2) If the value of oil determined under this subpart is based upon
a quantity and/or quality different from the quantity and/or quality at
the point of royalty settlement approved by the BLM for onshore leases,
adjust the value for those differences in quantity and/or quality.
(b) You may not claim a deduction from the royalty volume or
royalty value for actual or theoretical losses. Any actual loss that
you may incur prior to the royalty settlement metering or measurement
point will not be subject to royalty provided that BLM determines that
the loss is unavoidable.
(c) Except as provided in paragraph (b) of this section, royalties
are due on 100 percent of the volume measured at the approved point of
royalty settlement. You may not claim a reduction in that measured
volume for actual losses beyond the approved point of royalty
settlement or for theoretical losses that are claimed to have taken
place either prior to or beyond the approved point of royalty
settlement. Royalties are due on 100 percent of the value of the oil as
provided in this part. You may not claim a deduction from the value of
the oil for royalty purposes to compensate for actual losses beyond the
approved point of royalty settlement or for theoretical losses that
take place either prior to or beyond the approved point of royalty
settlement.
8. Section 206.106 is revised and redesignated as Sec. 206.123.
Sec. 206.123 How are operating allowances determined?
MMS may use an operating allowance for the purpose of computing
payment obligations when specified in the notice of sale and the lease.
MMS will specify the allowance amount or formula in the notice of sale
and in the lease agreement.
Note: The following Attachments will not appear in the Code of
Federal Regulations.
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State Station location County/offshore location
------------------------------------------------------------------------
Aggregation Points for Saint James, & Empire, Louisiana
------------------------------------------------------------------------
LA.................. Conoco Jct.............. Calcasieu
LA.................. Lake Charles............ Calcasieu.
LA.................. Texaco Jct.............. Calcasieu.
LA.................. Grand Chenier Term...... Cameron.
LA.................. Grand Isle.............. Jefferson.
LA.................. Bay Marchand Term....... Lafourche.
LA.................. Bayou Fourchon.......... Lafourche.
LA.................. Clovelly................ Lafourche.
LA.................. Fourchon Terminal....... Lafourche.
LA.................. Golden Meadow........... Lafourche.
LA.................. Blk. 55................. Offshore--South Pass.
LA.................. Blk. 13 (Wesco P.L. Offshore--South Pelto.
Subsea Tie-in).
LA.................. Blk. 172 Plat. D........ Offshore--South
Timbalier.
LA.................. Blk. 196 (Exxon P.L. Offshore--South
System Tie-in). Timbalier.
LA.................. Blk. 300................ Offshore--South
Timbalier.
LA.................. Blk. 35 Platform D...... Offshore--South
Timbalier.
LA.................. Blk. 52 Plat. A......... Offshore--South
Timbalier.
LA.................. Blk. 30................. Offshore--West Delta.
LA.................. Blk. 53................. Offshore--West Delta.
LA.................. Blk. 53 Plat. B......... Offshore--West Delta.
LA.................. Blk. 53B--Chevron P.L... Offshore--West Delta.
LA.................. Blk. 53B. Plat. Gulf Offshore--West Delta.
Refining Co.
LA.................. Blk. 83................. Offshore--West Delta.
LA.................. Blk. 28 Tie-in.......... Offshore--East Cameron.
LA.................. Blk 337 Subsea tie-in... Offshore-Eugene Island.
LA.................. Blk. 188 A Structure.... Offshore--Eugene Island.
LA.................. Blk. 23................. Offshore--Eugene Island.
LA.................. Blk. 259................ Offshore--Eugene Island.
LA.................. Blk. 316................ Offshore--Eugene Island.
LA.................. Blk. 361................ Offshore--Eugene Island.
LA.................. Blk. 51 B Platform...... Offshore--Eugene Island.
LA.................. Texas P.L. Subsea Tie-in Offshore--Eugene Island.
LA.................. Blk. 17................. Offshore--Grand Isle.
LA.................. Blk 69 B Plat........... Offshore--Main Pass.
LA.................. Blk. 144 Structure A.... Offshore--Main Pass.
LA.................. Blk. 298 Plat. A........ Offshore--Main Pass.
LA.................. Blk. 299 Platform....... Offshore--Main Pass.
LA.................. Blk. 42--Chevron P. L... Offshore--Main Pass.
LA.................. Blk. 42L................ Offshore--Main Pass.
LA.................. Blk. 77 (Pompano P.L. Offshore--Main Pass.
Jct.).
LA.................. Blk. 169................ Offshore--Ship Shoal.
LA.................. Blk. 203--Subsea Tie-in. Offshore--Ship Shoal.
LA.................. Blk. 208................ Offshore--Ship Shoal.
LA.................. Blk. 208 B Structure.... Offshore--Ship Shoal.
LA.................. Blk. 208 F.............. Offshore--Ship Shoal.
LA.................. Blk. 28................. Offshore--Ship Shoal.
LA.................. Blk.154................. Offshore--Ship Shoal.
LA.................. Ship Shoal Area......... Offshore--Ship Shoal.
LA.................. Blk. 255................ Offshore--Vermilion.
LA.................. Blk. 265 Platform A..... Offshore--Vermilion.
LA.................. Blk. 350................ Offshore--Vermilion.
LA.................. Main Pass............... Plaquemines.
LA.................. Main Pass Blk. 69--..... Plaquemines.
LA.................. Ostrica Term............ Plaquemines.
LA.................. Pelican Island.......... Plaquemines.
LA.................. Pilottown............... Plaquemines.
LA.................. Romere Pass............. Plaquemines.
LA.................. South Pass Blk. 24...... Plaquemines.
LA.................. South Pass Blk. 24 Plaquemines.
Onshore Plat.
LA.................. South Pass Blk. 27 Plaquemines.
Onshore Facility.
LA.................. South Pass Blk. 60A..... Plaquemines.
LA.................. Southwest Pass Sta...... Plaquemines.
LA.................. West Delta Blk. 53...... Plaquemines.
LA.................. Blk. 10--Structure A.... Offshore--South Marsh
Island.
LA.................. Blk. 139................ Offshore--South Marsh
Island.
LA.................. Blk. 139 Subsea Tap Offshore--South Marsh
Valve. Island.
LA.................. Blk. 207--Light House Offshore--South Marsh
Point A. Island.
LA.................. Blk. 268--Platform A.... Offshore--South Marsh
Island.
LA.................. Blk. 58A................ Offshore--South Marsh
Island.
LA.................. Blk. 6.................. Offshore--South Marsh
Island.
LA.................. Chalmette............... St. Bernard.
LA.................. Norco (Shell Refinery).. St. Charles.
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LA.................. Burns Term.............. St. Mary.
LA.................. South Bend.............. St. Mary.
LA.................. Caillou Island.......... Terrebonne.
LA.................. Gibson Term............. Terrebonne.
LA.................. Erath................... Offshore--Vermillion.
LA.................. Forked Island........... Offshore--Vermillion.
LA.................. Anchorage............... West Baton Rouge.
TX.................. Buccaneer Term.......... Brazoria.
TX.................. Mont Belvieu............ Chambers.
TX.................. Winnsboro............... Franklin.
TX.................. Texas City.............. Galveston.
TX.................. Houston................. Harris.
TX.................. Pasadena................ Harris.
TX.................. Webster................. Harris.
TX.................. Beaumont................ Jefferson.
TX.................. Lucas................... Jefferson.
TX.................. Nederland............... Jefferson.
TX.................. Port Arthur............. Jefferson.
TX.................. Port Neches............. Jefferson.
TX.................. Sabine Pass............. Jefferson.
TX.................. Corsicanna.............. Navarro.
TX.................. American Petrofina...... Nueces.
TX.................. Corpus Christi.......... Nueces.
TX.................. Harbor Island........... Nueces.
TX.................. Blk. 474--Intrsction. Offshore--High Island.
seg. III, III-7.
TX.................. Blk. A--571............. Offshore--High Island.
TX.................. End Segmennt III--10 Offshore--High Island.
(Blk. 547).
TX.................. End Segment II.......... Offshore--High Island.
TX.................. End Segment III--10..... Offshore--High Island.
TX.................. End Segment III--6...... Offshore--High Island.
TX.................. Rufugio Sta............. Rufugio.
TX.................. Midway.................. San Patricio.
TX.................. South Bend.............. Young.
------------------------------------------------------------------------
Aggregation Points for Alaska North Slope Valuation
------------------------------------------------------------------------
CA.................. Coalinga................ Fresno.
CA.................. Belridge................ Kern.
CA.................. Fellows................. Kern.
CA.................. Kelley.................. Kern.
CA.................. Lake.................... Kern.
CA.................. Leutholtz Jct........... Kern.
CA.................. Midway.................. Kern.
CA.................. Pentland................ Kern.
CA.................. Station 36-Kern River... Kern.
CA.................. Hynes Station........... Los Angeles.
CA.................. Newhall................. Los Angeles.
CA.................. Sunset.................. Los Angeles.
CA.................. Cadiz................... San Bernadino.
CA.................. Avila................... San Luis Obispo.
CA.................. Gaviota Terminal........ Santa Barbara.
CA.................. Lompoc.................. Santa Barbara.
CA.................. Sisquoc Jct............. Santa Barbara.
CA.................. Filmore................. Ventura.
CA.................. Rincon.................. Ventura.
CA.................. Santa Paula............. Ventura.
CA.................. Ventura................. Ventura.
CA.................. Rio Bravo............... County Unknown.
CA.................. Signa................... County Unknown.
CA.................. Stewart................. County Unknown.
------------------------------------------------------------------------
Aggregation Points for Midland Texas
------------------------------------------------------------------------
NM.................. Jal..................... Lea.
NM.................. Lovington............... Lea.
NM.................. Ciniza.................. McKinley.
NM.................. Bisti Jct............... San Juan.
NM.................. Navajo Jct.............. San Juan.
TX.................. Fullerton............... Andrews.
TX.................. Crane................... Crane.
TX.................. Caproch Jct............. Ector.
TX.................. Odessa.................. Ector.
TX.................. North Cowden............ Ector.
TX.................. Wheeler................. Ector.
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TX.................. El Paso................. El Paso.
TX.................. Roberts................. Glasscock.
TX.................. Big Spring.............. Howard.
TX.................. Phillips Hutchinson..... Howard.
TX.................. McKee................... Moore.
TX.................. Beaver Station.......... Ochiltree.
TX.................. Kemper.................. Reagan.
TX.................. Mason Jct............... Reeves.
TX.................. Eldorado................ Scheicher.
TX.................. Basin Station........... Scurry.
TX.................. Colorado City........... Scurry.
TX.................. McCamey................. Upton.
TX.................. Mesa Sta................ Upton.
TX.................. Halley.................. Winkler.
TX.................. Hendrick/Hedrick-Wink... Winkler.
TX.................. Keystone................ Winkler.
TX.................. Wink.................... Winkler.
------------------------------------------------------------------------
Aggregation Points for Cushing Oklahoma.
------------------------------------------------------------------------
CO.................. Denver.................. Adams.
CO.................. Cheyenne Wells Station.. Cheyenne.
CO.................. Iles.................... Moffat.
CO.................. Sterling................ Logan.
CO.................. Fruita.................. Mesa.
CO.................. Rangley................. Rio Blanca.
MT.................. Silver Tip Station...... Carbon.
MT.................. Alzada.................. Carter.
MT.................. Richey Station.......... Dawson.
MT.................. Baker................... Fallon.
MT.................. Cut Bank Station........ Glacier.
MT.................. Bell Creek Station...... Powder River.
MT.................. Clear Lake Sta.......... Sheridan.
MT.................. Poplar Station.......... Roosevelt.
MT.................. Billings................ Yellowstone.
MT.................. Laurel.................. Yellowstone.
ND.................. Fryburg Station......... Billiings.
ND.................. Tree Top Station........ Billiings.
ND.................. Lignite................. Burke.
ND.................. Alexander............... McKenzie.
ND.................. Keene................... McKenzie.
ND.................. Mandan.................. Morton.
ND.................. Tioga................... Ramberg.
ND.................. Ramberg................. Williams.
ND.................. Thunderbird Refinery.... Williams.
ND.................. Tioga................... Williams.
ND.................. Trenton................. Williams.
ND.................. Killdear................ County Unknown.
UT.................. Salt Lake Station....... Davis.
UT.................. Woods Cross............. Davis.
UT.................. Salt Lake City.......... Salt Lake.
UT.................. Aneth................... San Juan.
UT.................. Patterson Canyon Jct.... San Juan.
UT.................. Bonanza Station......... Uintah.
UT.................. Red Wash Station........ Uintah.
WY.................. Byron................... Big Horn.
WY.................. Central Hilight Sta..... Cambell.
WY.................. Rocky Point............. Cambell.
WY.................. Rozet................... Cambell.
WY.................. Sinclair................ Carbon.
WY.................. Big Muddy Sta........... Converse.
WY.................. Pilot Butte Sta......... Freemont.
WY.................. Cottonwood Jct.......... Hot Springs.
WY.................. Crawford Sta............ Johnson.
WY.................. Reno.................... Johnson.
WY.................. Sussex.................. Johnson.
WY.................. Cheyenne................ Laramie.
WY.................. Casper.................. Natrona.
WY.................. Noches.................. Natrona.
WY.................. Lance Creek Station..... Niobrara.
WY.................. Frannie Sta............. Park.
WY.................. Oregon Basin Sta........ Park.
WY.................. Guersey................. Platte.
WY.................. Wamsutter Sta........... Sweetwater.
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WY.................. Bridger Station......... Uinta.
WY.................. Divide Junction......... Uinta.
WY.................. Evanston Sta............ Uinta.
WY.................. Chatham Sta............. Washakie.
WY.................. Butte Sta............... Weston.
WY.................. Mush Creek Jct.......... Weston.
WY.................. Osage Station........... Weston.
------------------------------------------------------------------------
[FR Doc. 98-2704 Filed 2-5-98; 8:45 am]
BILLING CODE 4310-MR-P
This is a copy of a public record, reproduced as it was published. It is not legal advice, and it may not be the version a court would rely on. Check the official source before you cite it.