[Federal Register Volume 61, Number 58 (Monday, March 25, 1996)]
[Rules and Regulations]
[Pages 12022-12027]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 96-7038]
=======================================================================
-----------------------------------------------------------------------
DEPARTMENT OF THE INTERIOR
Minerals Management Service
30 CFR Part 260
RIN 1010-AC14
Deepwater Royalty Relief for New Leases
AGENCY: Minerals Management Service, Interior.
ACTION: Interim rule.
-----------------------------------------------------------------------
SUMMARY: The Outer Continental Shelf Deep Water Royalty Relief Act
(Act) authorizes the Secretary of the Interior (Secretary) to offer
Outer Continental Shelf tracts for lease with suspension of royalties
for a volume, value, or period of production. The Act requires the
Secretary to use this bidding system on tracts offered for lease in
water depths of 200 meters or more in parts of the Gulf of Mexico
through November 28, 2000. The Minerals Management Service (MMS)
intends to hold a lease sale in April 1996. This interim rule specifies
the royalty suspension terms under which the Secretary will make tracts
available for that sale.
DATES: Effective Date: This interim rule is effective April 24, 1996.
Comments: We will consider all comments we receive by April 24,
1996. We will begin review of comments at that time and may not fully
consider comments we receive after April 24, 1996.
ADDRESSES: Mail or hand-carry comments to the Department of the
Interior, Minerals Management Service, Mail Stop 4700, 381 Elden
Street, Herndon, Virginia 22070-4817, Attention: Chief, Engineering and
Standards Branch.
FOR FURTHER INFORMATION CONTACT: Walter Cruickshank, Offshore Minerals
Analysis Division, telephone (202) 208-3822.
SUPPLEMENTARY INFORMATION:
I. Background on the New Legislation
On November 28, 1995, President Clinton signed Public Law 104-58,
which included the Act. The Act contains four major provisions
concerning new and existing leases. New leases are tracts leased during
a sale held after the Act's enactment on November 28, 1995. Existing
leases are defined as all other leases.
First, section 302 of the Act clarifies the Secretary's pre-
existing authority in 43 U.S.C. 1337(a)(3) to reduce royalty rates on
existing leases in order to promote development, increase production,
and encourage production of marginal resources on producing or non-
producing leases. This provision applies only to leases in the Gulf of
Mexico west of 87 degrees, 30 minutes west longitude.
Second, section 302 also provides that ``new production'' from
existing leases in water depths of 200 meters or greater qualifies for
royalty suspensions if the Secretary determines that the new production
would not be economic in the absence of royalty relief. The Secretary
must then determine the appropriate royalty suspension volume on a
case-by-case basis, subject to specified minimums for leases not in
production prior to the date of enactment. This provision also applies
only to leases in the Gulf of Mexico west of 87 degrees, 30 minutes
west longitude.
Third, section 303 establishes a new bidding system that allows the
Secretary to offer tracts with royalty suspensions for a period,
volume, or value the Secretary determines. On February 2, 1996, we
published a final rule modifying the regulations governing the bidding
systems we use to offer OCS tracts for lease (61 FR 3800). New
Sec. 260.110(a)(7) addresses the new bidding system mandated by section
303 of the Act.
Fourth, section 304 provides that all tracts offered within 5 years
of the date of enactment in water depths of 200 meters or greater in
the Gulf of Mexico west of 87 degrees, 30 minutes west longitude, must
be offered under the new bidding system. The following
[[Page 12023]]
minimum volumes of production are not subject to a royalty obligation:
17.5 million barrels of oil equivalent (mmboe) for leases
in 200 to 400 meters of water,
52.5 mmboe for leases in 400 to 800 meters of water, and
87.5 mmboe for leases in more than 800 meters.
II. The Proposed April 1996 Lease Sale and the Need for an Interim
Rule
The Act requires the Secretary to issue implementing regulations
within 180 days of enactment. We published an advance notice of
proposed rulemaking (ANPR) in the Federal Register on February 23, 1996
(61 FR 6958), and informed the public of our intent to develop
comprehensive regulations implementing the Act. It sought comments and
recommendations to assist us in that process. We continue to collect
comments and conducted a public meeting in New Orleans on March 12-13,
1996, about the matters the ANPR addressed.
In accordance with the current 5-year OCS program, which provides
for annual lease sales in the Central and Western Gulf of Mexico, we
have scheduled a lease sale for April 24, 1996, for tracts in the
Central Gulf of Mexico. Many of these tracts are in water depths of 200
meters or more. Therefore, before we proceed with the sale, we must
issue regulations to implement section 304 of the Act.
We estimate that bonus bids at this sale could be as much as $300
million. Thus, delay of this sale would be contrary to the public
interest.
Also, a significant delay of the lease sale could seriously disrupt
investment activity important to both the national and regional
economies. The natural gas and oil industry relies on regularly
scheduled lease sales in the Gulf of Mexico to enable it to conduct its
annual land acquisition and exploration activities in an orderly and
predictable manner.
A full notice and comment rulemaking could not be completed prior
to the proposed April 1996 sale. Since the Act does apply to Central
and Western Gulf of Mexico lease sales for the next 5 years, we are
publishing this interim rule to allow the sale of deep-water tracts in
the Central Gulf of Mexico to proceed with a minimum of delay from the
original sale date established under the current 5-year OCS program. We
invite comments on this interim rule, and we also will consider them as
part of our review of responses to the ANPR mentioned above. Based on
comments received and experience gained at the upcoming sale, we may
include changes to the matters this interim rule addresses in the
comprehensive rulemaking that implements the remaining provisions of
the Act.
III. How To Implement Section 304 of the Act
Section 304 of the Act does not provide specific guidance on how to
apply the royalty suspension volumes to leases issued during sales
after November 28, 1995. The primary question is how to apply the
minimum royalty suspension volumes laid out in the statute. There are
several possibilities. One is to apply the royalty suspension volumes
on a unitary basis, so that there would be only one royalty suspension
volume in each water depth category in the entire area of the Gulf
subject to section 304. A second possibility is to apply the royalty
suspension volumes on the basis of geological fields, so that all
tracts producing from a single field collectively would receive the
royalty suspension volume. A third possibility is to apply the full
royalty suspension volume to each qualifying lease.
Ultimately, the choice among these alternatives is dictated by the
meaning of the statute. Unfortunately, the statutory language, as
discussed further below, does not unambiguously resolve this issue.
Turning first to the statutory text, section 304 is quite
indistinct. The first thing to note is that it is framed in the passive
voice (``suspension of royalties shall be set at [the following
volumes]''). This fails to make clear against what the royalty
suspension volumes should be applied. The section does speak in the
plural or multiple, referring to ``all tracts'' and ``any lease sale.''
This suggests that the royalty suspension volumes were not to be
applied on an individual lease basis. In section 302, by contrast,
Congress specified quite clearly that the owner(s) of each individual
lease could apply for a royalty suspension. (E.g., ``Such application
may be made on the basis of an individual lease or unit.'')
The legislative history helps clarify the meaning of the statutory
language. In bringing before the full Senate for vote the language that
eventually became law, Senator Johnston, the bill's primary sponsor,
explained that it was intended only to provide incentives for drilling
leases that would not otherwise be drilled and to bring new fields on
production:
It is only with respect to those leases that would not otherwise
be drilled, either existing or future leases, that this amendment
would provide that incentive. * * * The Secretary of the Interior
wanted the incentive to be sufficient but not too much. That took a
lot of negotiating. * * * [The legislation] should bring on at least
two new fields with approximately 150 million barrels of oil
equivalent from existing leases and it significantly improves the
economics of 10 to 12 possible and probable fields. ______ Cong.
Rec. S. 6731 (daily ed., May 16, 1995) [emphasis added].
This statement by the bill's prime sponsor, the most pertinent in
the legislative record, strongly suggests that the legislation was not
intended to provide each new lease in deep water the full royalty
suspension volume. If the legislation were interpreted to apply the
full royalty suspension volume to each lease, each new deep-water lease
issued for the next 5 years in fields already in production on the date
of enactment (November 28, 1995) would be entitled to the full royalty
suspension volume. That hardly would further the Act's purpose of
providing an economic incentive to develop new fields and ``leases that
otherwise would not be drilled.'' It might also skew production because
producers could slow development of existing leases to await new leases
in the field that would have royalty suspension volumes.
Legislators' statements in committee hearings sounded the same
theme--that the purpose was to bring new fields into production. Senate
Energy Committee Chairman Murkowski noted that the development of OCS
deep-water areas ``are dependent on the economics of the field * * *''
and Senator Johnston emphasized that ``the volumes [the royalty
suspension volumes specified in the legislation] were based on
assumptions of the economic field size relative to cost.'' Hearing on
S. 158 Before the Committee on Energy and Natural Resources, 104th
Cong., 1st Sess. 7, 39 (March 23, 1995).
In fact, the royalty suspension volumes set forth in section 304
for new tracts offered for lease originated with MMS. They were
developed out of technical analyses conducted by MMS of the royalty
suspension volumes needed for capital cost recovery in developing
unproduced oil and gas fields at various water depths in the Gulf of
Mexico. This helps explain the fact that the chief congressional
sponsor, Senator Johnston, expressly linked the royalty suspension
volumes in the Act to the cost of developing a field. It also counsels
that section 304 should, in order to be faithful to its proponents'
intent, be applied to make royalty suspension volumes available on a
field basis, rather than giving each and every individual lease the
full royalty suspension volume.
[[Page 12024]]
For the same reasons, section 304 should be read more broadly than
simply providing one royalty suspension volume at each specified depth
range (e.g., 200 to 400 meters) across the entire area of the Gulf
eligible for royalty relief. Such an application, done without regard
for fields or numbers of leases at those depth ranges, would not grant
sufficient incentive for any more than one new field at each water
depth. Such a reading, while possible to fit within the statutory
language, is clearly not in accord with the purposes of the Act.
The middle ground, applying the royalty suspension volumes in
section 304 on a field basis, is the most reasonable approach. In the
words of the bill's sponsor, only it fulfills what the Secretary
wanted, i.e., sufficient incentive to bring new fields into production.
Two other considerations support this outcome. First, as Congress
was doubtless aware when it enacted deepwater royalty relief, section
8(b), of the Outer Continental Shelf Lands Act (OSCLA) (43 U.S.C.
1337(b)) contains no fixed maximum tract size for a single lease.
Instead, it authorizes the Secretary to aggregate a large acreage into
a single tract for leasing if the Secretary ``finds a larger area is
necessary to comprise a reasonable economic production unit.'' Even if
section 304 were interpreted to mandate the Secretary to apply royalty
suspension volumes on an individual lease basis, the Secretary would
nevertheless retain the discretion, by virtue of section 8(b), to
choose a larger tract size for a single lease. Rather than going that
route, we have determined that section 304 is best interpreted to apply
royalty suspension volumes on a field basis. If royalty suspension
volumes were to be mandated on a lease basis, the Secretary would have
to seriously examine whether to lease larger tracts.
Second, as Congress was also doubtless aware when it enacted
deepwater royalty relief, the OCSLA sets no maximum royalty on Federal
oil and gas leases. Instead, it authorizes the Secretary to set an
initial royalty rate of ``no less than 12\1/2\ per centum'' (emphasis
added) per unit of production for new leases issued under the new
bidding system established by section 303 and mandated for use for the
next 5 years. If section 304 required the Secretary to provide a full
royalty suspension volume to each and every lease, the Secretary would
still have the discretion to set an initial royalty rate above the
statutory minimum or the rate traditionally used for Gulf of Mexico
leases. This higher royalty would kick in after the royalty-free
volumes for new leases in deep water terminated. This approach would
allow the Secretary to ensure that the development incentive provided
in the Act is consistent with giving the public a fair return on the
oil and gas resources that it owns. Once again, the interim rule, by
adopting the approach of applying the royalty suspension volumes on a
field basis, may avoid the need for including a higher royalty in the
lease at this time.
As these considerations illustrate, Congress preserved the
Secretary's broad discretion over tract size and royalty rate when it
came to enact deepwater royalty relief. By doing so, it in effect
preserved the authority of the Secretary to apply the royalty relief
volumes to fields rather than individual leases. This comports with
what we believe is the best and most reasonable interpretation of the
statutory language.
Based on our careful consideration of the Act, and its history, the
Secretary has settled upon this regulation. It provides for a
suspension of royalty payments for any one lease or several leases in a
field that finds and produces first the royalty-exempt volume of oil
equivalent from a new field. Thus, one lease may receive the whole
suspension volume or several leases may share it depending on which
lease(s) first produces the volume from the field.
IV. What the Interim Rule Provides
For the purposes of this rule, an ``eligible'' lease is a lease
that results from a sale held after November 28, 1995; is located in
the Gulf of Mexico in water depths 200 meters or deeper; lies wholly
west of 87 degrees, 30 minutes west longitude; and is offered subject
to a royalty suspension volume authorized by statute. We will add this
definition to 30 CFR 260.102.
The rule implementing section 304 of the Act will be in 30 CFR
260.110. As explained above, under Sec. 206.110(d)(1), we will allow
only one royalty suspension volume per new field (i.e., a field not
producing prior to November 28, 1995). That suspension volume is
available to the eligible leases in a new field based on which lease or
leases first produce the oil or gas until the suspension volume is
reached.
As an example, for eligible leases in a new field in 850 meters of
water, no royalties will be due from the first 87.5 mmboe of production
from all eligible leases producing from that field. [For the purpose of
this preamble, the Act's minimum royalty suspension volumes for each
water depth are assumed to apply although, for any particular lease
sale, we could increase the volume specified in the Act.] That
production could come from only one eligible lease, several eligible
leases, or all eligible leases in the field. In any event, only a total
of 87.5 mmboe will be allowed royalty free for that new field. Under
this rule, any lease-use production that otherwise is not subject to
royalty does not count toward the royalty suspension volume.
Under Sec. 206.110(d)(2), in each Final Notice of Sale, we will
specify the water depth of each tract offered for lease that is in at
least 200 meters of water. Once the lease is issued, our determination
of water depth is final. This rule applies even if the lease could be
shown actually to be in deeper water. We will not change the depth
determination and the applicable royalty suspension volume since one
factor we consider in determining the adequacy of the bonus bid is the
water depth specific royalty suspension volume that could apply to the
lease. As a result, the interim rule provides that the depth
classification by MMS is final and unappealable upon bid acceptance,
lease issuance, and lease acceptance by the high bidder for a tract. To
allow otherwise significantly alters the nature of the property right
offered at the lease sale, renders the lease auction and bid adequacy
process unreliable, and unfairly conveys an excessive benefit to the
successful bidder (or to the Federal Government if the water depth
later were determined to be shallower). It also would encourage endless
administrative and judicial litigation and appeals over varying
measurements of water depths. The Final Notice of Sale will also
specify the royalty suspension volumes for each of the prescribed water
depths, subject to the minimums stated in the Act.
Since all eligible leases in a field could share the royalty
suspension volume, each eligible lease must be assigned to a new or
existing field by the time production from that lease begins. In
accordance with our practice for over 20 years, we will assign a lease
to a field when a well on a lease qualifies as capable of producing in
paying quantities under the regulations at 30 CFR 250.11. If a well
does not qualify under the rule, we will assign the lease to a field
when hydrocarbons are first produced from the lease or the lease is
allocated production under an approved unit agreement.
We will either assign the lease to an existing field or designate a
new field. This interim rule includes the definition of field for this
purpose in 30 CFR 260.102. The definition is based on geology. We issue
the OCS Operations Field Names Master List each quarter,
[[Page 12025]]
with monthly updates, which lists all the tracts in each field on the
OCS.
Fields in deep water may consist of one or more leases, including
leases issued before and after November 28, 1995, and leases in
different water depths. Therefore, we must specify how to determine the
royalty suspension volume in many different circumstances. The simplest
factual case would be where a single eligible lease produces a new
field. The lessee would receive the entire royalty suspension volume if
that lease produces it. (See Sec. 206.110(d)(5).)
However, other cases will arise. Accordingly, in determining
individual lease eligibility for, and the volume of, royalty
suspensions, this is how the rule applies:
1. Under Sec. 206.110(d)(2), the Final Notice of Sale will specify
the royalty suspension volume for new fields in each of the specified
water depth ranges. Under Sec. 206.110(d)(3), at the time of first
production (not including test production) from an eligible lease in a
field, we will determine the royalty suspension volume available to
eligible lease(s) in that field based on the volumes specified in the
Final Notice of Sale.
2. If a new field consists of leases in different water depth
categories, the royalty suspension volume associated with the deepest
eligible lease applies. This is set forth in Sec. 206.110(d)(4).
3. If an eligible lease is designated as part of a field where any
current lease produced prior to November 28, 1995, that eligible lease
will not receive a royalty suspension volume from that field. Under
these circumstances, Congress certainly recognized that it is not
necessary to encourage production.
4. If an eligible lease is designated as part of a field where no
production from any current lease occurred prior to November 28, 1995,
a royalty suspension volume will apply to the eligible lease(s). The
royalty suspension volume will equal the volume specified for the
relevant water depth in the Final Notice of Sale. In this case, we view
the specified royalty suspension volume as the amount Congress
determined is needed to make a field economic to produce.
5. If a field did not produce before November 28, 1995, and
consists of more than one lease, no royalty is due on the first
production from any eligible leases in that field until they have
cumulatively produced the royalty suspension volume specified in the
Final Notice of Sale. Under Sec. 260.110(d)(6), the suspension volume
attributable to each lease depends upon which lease produces it first.
For example, if two eligible leases are producing from a new field in
300 meters of water, their royalty suspension would end when production
from those leases reaches 17.5 mmboe, the royalty suspension volume for
that water depth. If one lease had produced 10.0 mmboe and the second
lease had produced 7.5 mmboe, that would determine their respective
suspension volumes.
6. The addition of an eligible lease to a field that has an
established royalty suspension volume will not change the field's
royalty suspension volume, even if the added lease is in deeper water.
Under Sec. 260.110(d)(7), the added lease will benefit from the field's
royalty suspension only to the extent of its production before
cumulative production from all eligible leases in the field equals the
field's previously established royalty suspension volume.
7. Under Sec. 260.110(d)(8), if we reassign a well on an eligible
lease to another field, the past production from that well will count
toward the royalty suspension volume, if any, specified for the new
field to which it is assigned. The past production will not be counted
toward the suspension volume, if any, for the first field.
8. Section 260.110(d)(9) provides that you may receive the royalty
relief only if your entire lease is west of 87 degrees, 30 minutes west
longitude. This requirement is expressly provided in the Act. A new
field that lies on both sides of this meridian will receive a royalty
suspension volume only for those new leases lying west of the meridian
and in 200 meters of water or more.
9. The Act provides royalty suspension volumes only to leases in at
least 200 meters of water. We will establish the water depth for each
lease in the Final Notice of Sale. If a field includes leases in both
less than 200 meters and more than 200 meters of water, only those
eligible leases in water depths of at least 200 meters may share in the
royalty suspension volume.
10. Under Sec. 260.110(d)(10), a lease may obtain more than one
royalty suspension volume. If a new field is discovered on an eligible
lease that already benefits from the royalty suspension volume for
another field, production from that new field receives a separate
royalty suspension. For example, assume an eligible lease already
receives up to 17.5 mmboe of royalty-free production from a field in
300 meters of water. If another new field is discovered under that
lease, the lease may obtain a second royalty suspension of up to 17.5
mmboe on production prescribed for that second field. Your royalty
suspension volume for the second field depends upon whether other
eligible leases produce in that second field. This second royalty
suspension volume may occur even if the same production facilities
develop both fields. However, the royalty suspension volumes are
specific to the individual fields. Thus, for example, if the lease
eventually produces 10 mmboe from wells in one field and 50 mmboe from
wells in the other, and there are no other eligible leases in either
field, the total royalty-free production will be 27.5 mmboe (i.e., 10
plus 17.5 mmboe).
We understand that other factual situations may arise under this
rule. Those situations must be resolved consistent with the principles
described above.
V. Additional Examples
The following examples further clarify the situations listed above.
1. If a field consists only of two eligible leases, one in 750
meters of water and one in more than 800 meters, the field will have a
royalty suspension volume of 87.5 mmboe. The first 87.5 mmboe produced
from either or both leases in the field would be royalty-free.
2. If an eligible lease in 300 meters of water is added to a field
consisting of leases issued from a sale held prior to November 28,
1995, and that field begins production after that eligible lease is
added, the field's suspension volume would be 17.5 mmboe. The eligible
lease may produce up to 17.5 mmboe royalty-free. However, if that lease
only produces 10 mmboe over its productive life and no other eligible
leases are part of the field, that field will receive only 10 mmboe of
relief.
3. If an eligible lease in 600 meters of water is added to a
producing field consisting of leases issued from sales held prior to
November 28, 1995, and there are no other eligible leases in the field,
and that field started continuous production (other than test
production) after November 28, 1995, the lease could receive 52.5 mmboe
of royalty suspension regardless of the previous production. However,
if the new lease only produces 10 mmboe over its productive life and no
other eligible lease is added to the field, that field will receive
only 10 mmboe of relief under this provision.
4. If an eligible lease in 850 meters of water is added to a field
that already has an established royalty suspension volume from other
eligible leases in the field in shallower water, the field's royalty
suspension volume will not change. For example, if production from the
field already amounts to 30 mmboe of its 52.5 mmboe royalty suspension
volume when the additional lease
[[Page 12026]]
begins production, that lease may share in the field's remaining 22.5
mmboe of royalty-free production to the extent that it first produces
some portion of the remaining 22.5 mmboe. This example also shows that
even though the added lease was in deeper water, it does not increase
the royalty suspension volume already established for that field by a
shallower lease.
VI. Technical Issues Related to Royalty Suspension Volumes
For purposes of accounting for production accruing to the royalty
suspension volume, 5.62 thousand cubic feet of natural gas equal one
barrel of oil equivalent, as measured at 15.025 pounds per square inch
(psi) pressure, 60 degrees Fahrenheit, and fully saturated
(Sec. 260.110(d)(11)). This is the conversion factor which has been
used traditionally in the Gulf of Mexico.
A royalty suspension will continue until the end of the month in
which the cumulative production from eligible leases in the field
reaches the royalty suspension volume for the field.
When a field is not being jointly developed, lessees may not know
when the field has produced all of its royalty suspension volume. We
will provide monthly field production data to all lessees in a field.
However, this data may not become available until shortly after a
field's production exceeds the royalty suspension volume. In such
cases, royalties still will be due on the last day of the second month
following the month in which cumulative production from the field
reaches the royalty suspension volume. Any royalties paid late will be
subject to interest pursuant to 30 CFR 218.54.
Nothing in this interim rule affects the eligibility of a lessee to
apply for royalty relief under the other provisions of the Act or under
existing regulatory authority. Lessees of leases issued as the result
of a lease sale held before November 28, 1995, whether or not they are
part of a field that produced prior to that date, may apply for a
royalty suspension volume under section 302 of the Act. Content,
supporting documentation, and procedures for submission and review of
such applications will be addressed in the comprehensive rulemaking
mentioned above. Further, any OCS lessee may apply for a reduction or
elimination of its lease royalty rate or net profit share under section
8(a)(3) of the OCSLA (as amended by the Act with respect to leases in
parts of the Gulf of Mexico).
VII. Administrative Matters
Executive Order (E.O.) 12866
The interim rule is significant due to novel policy issues arising
out of legal mandates, and the Office of Management and Budget (OMB)
has reviewed this rule. A copy of this determination is available from
MMS.
Offering tracts subject to royalty suspension volumes should result
in accelerated investment on the OCS. In deep water, exploration wells
can cost more than $30 million, and field development can cost as much
as $1 billion. However, the best assumption is that most of this
investment would eventually occur under any royalty terms; the royalty
suspension tends to make this activity occur earlier.
We analyzed two alternatives for implementing section 304 of the
Act. The approach in this interim rule (MMS approach) is where there is
a single suspension volume for each field at the volumes designated in
the legislation. The alternative approach is where the full royalty
suspension volume applies to each lease.
For scheduled 1996 lease sales in the deep-water Gulf of Mexico,
the alternative approach results in more resources being leased (905
mmboe versus 680 mmboe) and higher bonuses ($261 million versus $113
million) than the MMS approach. However, the MMS approach generates
higher royalty payments over the productive life of the lease ($352
million versus $40 million) than the alternative approach. On a net
present value basis, the MMS approach also collects more revenue for
the Treasury ($284 million versus $277 million). On the basis of
revenues-per-boe, the MMS approach generates more than twice the
nominal revenues and 35 percent more revenues-per-boe in net present
value than the alternative approach.
We chose the approach embodied in this interim rule because:
The Act's primary author stated that he intended the Act
to encourage production from new fields without providing too much
relief,
The MMS approach provides a substantial incentive for new
investment and production in deep water while still ensuring a
reasonable return to the Treasury, and
The minimum suspension volumes specified in the Act were
derived from an analysis of fields, not individual leases.
Regulatory Flexibility Act
The Department of the Interior (DOI) has determined that this
interim rule will not have a significant effect on a substantial number
of small entities. In general, the entities that engage in offshore
activities in the deep waters of the Gulf of Mexico are not considered
small due to the technical and financial resources and experience
necessary to safely conduct such activities.
Administrative Procedure Act
We have determined, in accordance with 5 U.S.C. 553(b)(3)(B) of the
Administrative Procedure Act, that a notice of proposed rulemaking is
not required and is impracticable in the issuance of this rule. The
comment period associated with a proposed rulemaking would require that
we delay the upcoming lease sale in the Central Gulf of Mexico for a
significant period. The public interest is best served by collecting
the sale revenues for the Treasury in a timely manner and avoiding
direct detrimental effects on the offshore industry's investment plans.
We invite comments on this interim rule so changes can be made in the
future, if warranted.
Paperwork Reduction Act
The rule contains no new reporting and recordkeeping requirements.
Takings Implication Assessment
The DOI certifies that this rule does not represent a governmental
action capable of interference with constitutionally protected property
rights. A Takings Implication Assessment prepared pursuant to E.O.
12630, Government Action and Interference with Constitutionally
Protected Property Rights, is not required.
E.O. 12988
The DOI has certified to the OMB that this regulation meets the
applicable standards provided in section 3(b)(2) of E.O. 12988.
National Environmental Policy Act
The MMS has examined the interim rulemaking and have determined
that this rule does not constitute a major Federal action significantly
affecting the quality of the human environment pursuant to section
102(2)(C) of the National Environmental Policy Act of 1969 (42 U.S.C.
4332).
List of Subjects in 30 CFR Part 260
Continental shelf, Government contracts, Minerals royalties, Oil
and gas exploration, Public lands--mineral resources.
[[Page 12027]]
Dated: March 13, 1996.
Bob Armstrong,
Assistant Secretary, Land and Minerals Management.
For the reasons set forth in the preamble, the Minerals Management
Service amends 30 CFR part 260, Subpart B--Bidding Systems, as follows:
PART 260--[AMENDED]
1. The authority citation for part 260 continues to read as
follows:
Authority: 43 U.S.C. 1331 and 1337.
2. Section 260.102 is amended by adding in alphabetical order the
definitions for ``Eligible Lease'' and ``Field'' which read as follows:
Sec. 260.102 Definitions.
* * * * *
Eligible lease means a lease that results from a sale held after
November 28, 1995; is located in the Gulf of Mexico in water depths 200
meters or deeper; lies wholly west of 87 degrees, 30 minutes west
longitude; and is offered subject to a royalty suspension volume
authorized by statute.
Field means an area consisting of a single reservoir or multiple
reservoirs all grouped on, or related to, the same general geological
structural feature and/or stratigraphic trapping condition. There may
be two or more reservoirs in a field that are separated vertically by
intervening impervious strata, or laterally by local geologic barriers,
or by both.
* * * * *
3. In Sec. 260.110, paragraph (d) is added to read as follows:
Sec. 260.110 Bidding systems.
* * * * *
(d) This paragraph explains how the royalty suspension volumes in
section 304 of the Outer Continental Shelf Deep Water Royalty Relief
Act, Pub. L. 104-58, apply to eligible leases. For purposes of this
paragraph, any volumes of production that are not royalty bearing under
the lease or the regulations in this chapter do not count against
royalty suspension volumes. Also, for the purposes of this paragraph,
production includes volumes allocated to a lease under an approved unit
agreement.
(1) Your eligible lease may receive a royalty suspension volume
only if your lease is in a field where no current lease produced oil or
gas (other than test production) before November 28, 1995. Paragraph
(d) of this section applies only to eligible leases in fields meeting
this condition.
(2) The Final Notice of Sale will specify the water depth for each
eligible lease. Our determination of water depth for each lease is
final once we issue the lease. The Notice also will specify the royalty
suspension volume applicable to each water depth. The minimum royalty
suspension volumes for fields are:
(i) 17.5 mmboe in 200 to 400 meters of water;
(ii) 52.5 mmboe in 400 to 800 meters of water; and
(iii) 87.5 mmboe in more than 800 meters of water.
(3) When production (other than test production) first occurs from
any of the eligible leases in a field, we will determine what royalty
suspension volume applies to the eligible lease(s) in that field. The
determination is based on the royalty suspension volumes specified in
paragraph (d)(2) of this section.
(4) If a new field consists of eligible leases in different water
depth categories, the royalty suspension volume associated with the
deepest eligible lease applies.
(5) If your eligible lease is the only eligible lease in a field,
you do not owe royalty on the production from your lease up to the
applicable royalty suspension volume.
(6) If a field consists of more than one eligible lease, payment of
royalties on the eligible leases' initial production is suspended until
their cumulative production equals the field's established royalty
suspension volume. The royalty suspension volume for each eligible
lease is equal to each lease's actual production (or production
allocated under an approved unit agreement) until the field's
established royalty suspension volume is reached.
(7) If an eligible lease is added to a field that has an
established royalty suspension volume, the field's royalty suspension
volume will not change even if the added lease is in deeper water. The
additional lease may receive a royalty suspension volume only to the
extent of its production before the cumulative production from all
eligible leases in the field equals the field's previously established
royalty suspension volume.
(8) If we reassign a well on an eligible lease to another field,
the past production from that well will count toward the royalty
suspension volume, if any, specified for the new field to which it is
assigned. The past production will not be counted toward the suspension
volume, if any, from the first field.
(9) You may receive a royalty suspension volume only if your entire
lease is west of 87 degrees, 30 minutes west longitude. A field that
lies on both sides of this meridian will receive a royalty suspension
volume only for those eligible leases lying entirely west of the
meridian.
(10) Your lease may obtain more than one royalty suspension volume.
If a new field is discovered on your eligible lease that already
benefits from the royalty suspension volume for another field,
production from that new field receives a separate royalty suspension.
(11) You must measure natural gas production subject to the royalty
suspension volume as follows: 5.62 thousand cubic feet of natural gas
equals one barrel of oil equivalent, as measured at 15.025 psi, 60
degrees Fahrenheit, and fully saturated.
[FR Doc. 96-7038 Filed 3-22-96; 8:45 am]
BILLING CODE 4310-MR-P
