[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]



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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.

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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