[Federal Register Volume 66, Number 37 (Friday, February 23, 2001)]
[Rules and Regulations]
[Pages 11512-11523]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 01-4490]



[[Page 11511]]

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Part V





Department of the Interior





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Minerals Management Service



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30 CFR Parts 218, 256, and 260



Outer Continental Shelf Oil and Gas Leasing; Final Rule



Outer Continental Shelf, Central Gulf of Mexico, Oil and Gas Lease Sale 
178, Part 1; Notice

Federal Register / Vol. 66, No. 37 / Friday, February 23, 2001 / 
Rules and Regulations

[[Page 11512]]


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DEPARTMENT OF THE INTERIOR

Minerals Management Service

30 CFR Parts 218, 256, and 260

RIN 1010-AC-69


Outer Continental Shelf Oil and Gas Leasing

AGENCY: Minerals Management Service (MMS), Interior.

ACTION: Final rule.

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SUMMARY: This bidding rule establishes the leasing incentive framework 
we will use to issue Outer Continental Shelf (OCS) leases after 
November 2000. It also presents a plain-language revision of the 
existing rules for bidding systems and joint bidding restrictions. It 
does not change the current policies on and requirements for bidding 
systems, joint bidding restrictions, or royalty suspensions for leases 
issued before December 2000. It does add one minor reporting 
requirement for all leases issued with royalty suspension and specifies 
the allocation of royalty relief on a field having leases issued before 
and after 2000. It also clarifies and rewrites in plain-language the 
current rental regulations at 30 CFR 218.151 to provide for lessees to 
pay rental fees during the period of royalty suspension.

DATES: This final rule is effective March 26, 2001.

FOR FURTHER INFORMATION CONTACT: Marshall Rose, Economics Division, at 
(703) 787-1536.

SUPPLEMENTARY INFORMATION: On September 14, 2000, we published a 
proposed rule in the Federal Register (65 FR 55476) stating that we 
intend to continue OCS leasing incentives in the deep water Gulf of 
Mexico (GOM) but will implement incentive provisions differently from 
previous lease sales. Also, we used this occasion to restate in a 
plain-language format the existing bidding system rules without 
altering their meaning. This final rule now modifies some provisions in 
the September 14, 2000, proposed rule.
    We proposed four primary changes to the way we have been 
implementing leasing incentives. In the future, we will establish in 
the notice of sale, instead of in regulation, the size and form of 
royalty relief and associated parameters, such as the water depth 
demarcations where royalty suspension (RS) volumes apply and the price 
thresholds above which we interrupt RS. Unlike eligible leases issued 
from 1996 through 2000, future deep water leases, even those issued 
with RS volumes, may apply for supplemental royalty relief under our 
discretionary authority in 30 CFR 203. We will assign RS volumes to 
individual leases rather than, as previously, to fields. Finally, 
lessees will owe rental but no minimum royalties in any full year in 
which they pay no royalties on production. Currently, lessees owe 
rentals until discovery and then minimum royalties until production 
under royalty suspension begins. The intent to change the current rule 
and provide for rentals during royalty suspension periods was not 
perfectly captured in the proposed regulation, but was included in the 
preamble to the proposed rule. The preamble explained that rentals 
during royalty suspension periods are analogous to a holding fee 
collected during capital recovery periods when net profit share leases 
pay rental but no royalty. In the proposed rule we asked for comments 
on these leasing incentive adjustments.
    In conjunction with this rulemaking, on November 16, 2000, we 
published another proposed rule in the Federal Register (65 FR 58258) 
describing adjustments to our discretionary relief process. Among other 
things, this discretionary proposed rule makes leases issued after 
November 2000 in water 200 meters or deeper in the GOM wholly west of 
87 degrees, 30 minutes West longitude eligible to apply for 
supplemental royalty relief. Also, it proposed to modify the relief 
qualification process in ways that should allow more applicants on pre-
Act leases to qualify for relief and more flexibility for companies on 
both pre-Act and all new deep water leases to adjust development plans 
without sacrificing the chance for relief. We also sought and will 
consider comments we receive on that rule.

Response to Comments

    Thirteen respondents--a joint one from 6 oil and gas industry 
associations, a separate one from one of those associations, 10 oil and 
gas companies and the Department of Energy--submitted comments on the 
leasing incentive and bidding rule. Copies of all the comments we 
received are available on our website at http://www.mms.gov/federalregister/PublicComments/rulecomm.htm.
    Several comments took issue with some of our bidding system rules. 
As we are not proposing to change the substance of the existing rules, 
we take those comments as indicative of confusion created by our plain-
language rewrite. We clarify in this final rule those confusing 
portions of the proposed rewrite.
    The requirement to notify us when royalty-free production begins is 
the only change from the current regulation that we proposed to the way 
royalty suspensions apply to eligible leases issued from 1996 through 
2000. No respondents objected to this notification requirement and we 
finalized that provision without modification. The only other new 
element that affects existing eligible leases is that a future RS lease 
may be on the same field. The new regulations in Sec. 260.124 govern 
royalty suspension in this situation.
    Most comments addressed specific questions raised in the 
introduction to the proposed rule. The following summarizes those 
comments and our responses in four sections--design of future royalty 
suspensions, adjustable lease-based royalty suspension, rental payments 
and relief suspension during high prices, and bidding issues.

Design Issues

    Four questions sought guidance on design issues for future lease 
sales. Responses to the question on what factors we should consider, 
and how we should consider them, when choosing water depths at which to 
offer royalty relief focused on four items:
    <bullet> Shortage of rigs capable of drilling in water depths 
greater than 1600 meters;
    <bullet> Lack of infrastructure in water depths greater than 1600 
meters;
    <bullet> The multitude of challenges (reservoir connectivity, 
reservoir performance, rig price fluctuations, limited production 
experience, undeveloped and relatively untested technology, distance 
from support infrastructure, higher development costs, and shallow 
water flow) to operations in water depths greater than 1500 meters; and
    <bullet> The relatively lower quality of remaining prospects in the 
200 to 1600 meter water depth area.
    No one suggested ways to rank or measure the relative significance 
of these factors or how to relate them to the issue of whether we 
should provide any RS volumes. Also, the comments seem to argue that a 
rationale can be made for royalty relief in all deep water.
    Responses to the question on what elements other than water depth 
to consider, and how we should consider them, in deciding on the size 
of RS volumes also can be categorized into four groups:
    <bullet> Unusual drilling challenges such as subsalt targets, 
extreme well depths, and drilling encountering high pressure/high 
temperature zones;
    <bullet> Unusual production challenges such as distance to 
available

[[Page 11513]]

infrastructure, high sulphur and low API gravity crude oils, and areas 
with a history of poor reservoir performance;
    <bullet> The value of increased competition from greater bidding 
interest sparked by royalty relief; and
    <bullet> Shortage of domestic investment alternatives for the 
offshore oil and gas industry due to the absence of OCS lands available 
for leasing outside the GOM.
    Again, beyond identification of these elements, the comments 
offered little in the way of guidance on how to evaluate these 
considerations relative to others such as the need to obtain fair 
market value for public resources and the desire to use the incentive 
efficiently. Nonetheless, like those to the previous question, these 
comments identify elements we will consider in choosing RS parameters. 
This rule does not establish those parameters, so those comments will 
be considered more fully as part of future notice of sale processes 
that will establish these parameters.
    The question on the choice between low RS volumes followed by 
normal royalty rates or high RS volumes followed by above normal 
royalty rates found a large preference for the former. The principal 
reasons given included aversion to variable royalty rates, a wish not 
to confound the bidding and exploration incentive offered by RS volumes 
with disincentive changes in other lease terms, and a recognition that 
supplemental relief can reinforce modest RS volumes where truly needed. 
One comment did note that smaller, riskier prospects may benefit more 
from the larger RS volumes than a lower eventual royalty rate.
    The final design question about the shift in risk associated with 
RS volumes elicited no responses that smaller companies feel 
disadvantaged either in bidding or development relative to larger 
companies.
    One comment suggested that we are defining too narrowly this 
framework for royalty relief by mentioning only suspension of royalty 
for a volume of production. The Deep Water Royalty Relief Act (the Act) 
also authorized suspensions for a time or value of production. To keep 
open that possibility, we refer to a more general royalty suspension 
rather than a royalty suspension volume in Secs. 260.120, 260.121 and 
260.124.

Adjustable Leased-based Royalty Suspension

    Responses generally agreed with our observation that lease-based 
royalty suspension is preferable to field-based royalty suspension. 
Many comments voiced the need for certainty and stability in lease sale 
terms and asserted that field-based RS volumes introduce uncertainties 
into planning that diminish some of the positive impact of royalty 
relief on prospect economics. Several comments tentatively supported 
lease-based relief, but worried that intermixing the lease-based 
program with the field-based program may create uncertainty. We 
disagree because the proposed provisions confine uncertainty about 
realization of RS volumes to eligible leases; i.e., those issued under 
the field-based system. The current regulation makes it clear that a 
field's RS volume is to be shared by all the leases in a field entitled 
to share the royalty suspension volume. The new RS leases are simply a 
new kind of lease entitled to share this volume. The new element is 
that, unlike with eligible leases or pre-Act leases that qualify for an 
RS volume, the field's production timing and magnitude do not affect 
the royalty relief available to the new RS leases. Also, the proposed 
provisions do not increase the degree of uncertainty faced by eligible 
or pre-Act leases, had the field-based system continued. New leases 
issued with lease-based RS volumes share from a volume sufficient to 
make the field economic, just as would other eligible leases or pre-Act 
leases that qualify for a royalty suspension.
    In the proposed rule, we inadvertently proposed to change the 
period allowed for a challenge to a field designation from 15 to 30 
days in Secs. 260.114 and 260.124. We did not mention this as a change 
in the preamble to the proposed rule because we did not intend to 
propose this change. No one commented on the change. To avoid the 
inevitable confusion and administrative problem of different appeal 
periods for leases issued at different times, we adjust the proposed 
rule language to retain the 15-day appeal period to all leases.
    Additional steps that some respondents requested to reduce the 
uncertainty for eligible leases are beyond the scope of this 
rulemaking. The main step identified was designation of which blocks 
are on which fields before drilling proves the presence of 
hydrocarbons. Note that we publish the procedure we use to decide on 
which field a well on a lease lies, so companies can form their own 
judgment of what we will decide after the well is drilled. It is our 
position that to do more and actually preview our likely field decision 
could risk divulging others' proprietary data and possibly misdirect 
companies if we subsequently acquire new well or other data.
    Some responses to our question about basing uniform RS volumes on 
the needs of a typical tie-back-sized field pointed out that in doing 
so we should consider additional factors. Those factors include:
    <bullet> the expectation that the bigger and better situated tie-
back fields already have been leased,
    <bullet> the uncertainty a resource owner faces about access to 
another's facilities, and
    <bullet> the chance that user charges will transfer the benefit of 
the RS from the reserve owner to the facility owner.
    Others simply opposed basing RS volumes on tie-backs at all. Those 
that opposed using tie-backs as a basis argued that many potential tie-
back-sized fields may be developed as stand-alones because they have 
one or more of the following characteristics. The fields:
    (1) Consist of multiple reservoirs that require numerous 
recompletions;
    (2) Involve a large numbers of wells because they lack reservoir 
continuity; or
    (3) Depend on the use of secondary recovery techniques (e.g., water 
injection). Others noted the current absence of infrastructure to host 
tie-backs in ultra-deep water.
    In general, we view situations with these unusual characteristics 
as exceptions to be handled by the combination of automatic and 
supplemental relief. An efficient leasing incentive must focus on a 
standard volume adequate to encourage bidding and exploration on fields 
not yet leased and the kind of development most likely to occur on 
those fields. Should experience indicate, we retain the flexibility 
under this new rule to offer larger RS in the future. In the meantime, 
offering larger RS volumes based on stand-alone development would grant 
excessive royalty relief for the way many of the unleased fields are 
likely to develop.
    On the subject of supplemental relief, we received one comment 
related to the breadth of our royalty relief authority. One respondent 
noted that the OCS Lands Act gives the Secretary of the Interior 
discretionary authority to reduce or eliminate royalties on producing 
or non-producing leases, and that the Act does not specifically 
prohibit granting discretionary relief outside the GOM west of 87 
degrees, 30 minutes West longitude. We disagree because the OCS Lands 
Act only authorizes royalty relief to increase production, implying 
that the lease is already on production. Only the Act authorized relief 
to promote development, implying that a lease has not yet produced, and 
the Act limits these authorities to the GOM west of 87 degrees, 30 
minutes West longitude.

[[Page 11514]]

    Several responses to our intention to assume two to three leases 
per field developed as a tie-back argued that we should make no 
assumption about field size or makeup. Others advocate adjustment in 
the lease-based relief for fields that prove to underlie fewer leases. 
Yet many of the same respondents urged certainty and clarity on future 
royalty relief provisions. Since we typically estimate the economics of 
unleased and undiscovered resources on a field basis, lease-based 
relief requires some transformation from field to lease. Our judgment 
is that we make relief more certain when we estimate a generic field's 
financial needs and convert this to a lease size before the lease sale. 
The most logical and administratively simple way to do the conversion 
is by using typical numbers of leases per field derived from relevant 
experience. The alternative of waiting to set the RS volume until a 
field is discovered and its boundaries determined does not eliminate 
the uncertainty about the RS volume that a lease ultimately receives. 
In fact, it would reintroduce some of the uncertainty and contention we 
currently have with the field as the primary basis of royalty relief.
    Two features are likely to help correct any errors in an assumption 
about the specific number of leases per field. First, the assumption of 
two to three leases per field is based on our experience to date with 
fields, most of which we recognize are in shallow water and involve a 
smaller average field size. Our analysis shows that the deep water 
fields likely to be leased and discovered over the next few years will 
tend to cover more leases. In that circumstance, lease specific relief 
set at \1/2\ to \1/3\ the volume appropriate for a typical field will 
result in the actual field getting more royalty relief. Second, if 
experience proves that two to three leases are not representative for 
deep water fields, we can then adjust RS volumes for new leases offered 
in subsequent sales.
    Respondents generally applauded our intention to wait at least 3 
years before modifying the initial RS volumes and the other parameters. 
Benefits cited included easier planning and better decisions because a 
3-year commitment allows time for seismic acquisition and 
interpretation. This time period also affords MMS the opportunity to 
examine how well the program is working over several lease sales. One 
comment recommended a 5-year commitment coinciding with our 5-year OCS 
leasing program. While we recognize the value of a multiyear commitment 
on lease terms, we do not believe it prudent to include it in a 
regulation. Rapid changes either in the GOM or in the larger oil and 
gas market may indicate a change in lease terms that can be 
accomplished more expeditiously in the sale notice.

Rental Policy Change and Relief Suspension During High Prices

    Respondents identified three kinds of effects--conflicting message, 
minimal, and confusion--from our proposal to extend the rental 
obligation until royalty payments begin. The conflicting message is 
that rental payments detract from the RS incentive by imposing a 
payment during the period when we suspend royalties. Others admitted 
this payment is minimal given the many millions it takes to develop 
successfully deep water prospects and the value of the royalties saved 
due to the RS and is consistent with a long tradition of an annual 
maintenance fee on OCS leases. Confusion could arise because existing 
lease forms have first a rental then a minimum royalty equivalent to 
the rental, even before production begins. Future lease forms will 
impose only a rental during periods when no royalty payments are due 
and then impose minimum royalties only as a floor for those royalty 
payments. We do clarify in 30 CFR 218.151 that the due date for rental 
after a discovery shifts to the end of the lease year.
    One comment recommended simply extending minimum royalties to the 
RS periods, rather than subjecting all future leases to rentals for an 
extended period. The proposed treatment has a similar effect on future 
leases sold without an RS, as they would pay no more in fees than they 
would under the previous rules. While there could be some difference 
for leases sold with RS, we deem it inadvisable to introduce the 
administrative burden of making a hypothetical royalty calculation when 
no royalty is really due. Clarifying the designation of this single 
holding fee as a rental payment when no royalty is due should help 
avoid future confusion.
    On another rental issue, some respondents expressed concern that we 
are changing the requirements about collecting rentals from a non-
producing part of a partitioned lease. Our requirements on this issue 
have not changed from what they were before this plain-language 
rewrite. We do not collect rentals from the non-producing part of a 
lease. However, when a newly formed lease occurs as a result of 
segregation, we do collect rental from a non-producing part of a block.
    Some respondents opposed having price thresholds set in sale 
notices and perhaps periodically adjusted, even though any adjustments 
would apply only to newly issued leases, not those already issued. 
Price thresholds are oil and gas prices above which lessees owe 
royalties despite RS. Most comments objected to the reduced 
predictability amidst all the other uncertainty in deep water 
development. It is important to reiterate that once set for a given 
lease, the price threshold will not change. Only future leases would be 
subject to any new price threshold. One comment opposed adjusting price 
thresholds in general since oil and gas price increases drive up costs 
due to increased utilization of rigs, labor, and equipment. We continue 
to believe it is better to be able to adjust thresholds if necessary 
for newly issued leases. Otherwise, we could be locked into an 
inappropriate price threshold. Perceptions about future prices both 
drive investment decisions and evolve over time, so the option to 
change price thresholds for new leases benefits the initial threshold 
choice because it allows for future adjustments.
    A related issue drew either no comments or expressions of 
confusion. Current policy, following the language of the Act, makes 
royalties due from the whole previous year if that year's average price 
exceeds the threshold. That fact cannot be known for certain until 
several months after the end of a year, so lessees could end up at that 
time owing back royalties for the past year. One alternative is to 
apply the thresholds on a real time, rather than retrospective basis. 
The absence of comments on this issue may simply reflect an acceptance 
of the existing administrative procedures stated in the Act.
    Responses to our question about the appropriate magnitude of price 
thresholds raised a variety of issues. Some wanted no price thresholds, 
since those willing to take the risks of deep water exploration and 
production should not be additionally burdened with the risk of losing 
the RS incentive. Others essentially took the same position by stating 
that any price thresholds should be so high that they are not breached 
by historic price fluctuations, since industry bears the brunt of price 
cycles. We disagree with this position because we design RS terms 
assuming some price expectations by the lessee, and those terms lose 
legitimacy when prices diverge too much from those expectations.
    Several respondents agreed that the price thresholds with annual 
inflation adjustments are reasonable but see no reason to change from 
the levels set in the Act. Absent compelling analysis supporting the 
Act's choice of price

[[Page 11515]]

thresholds, we estimated appropriate ones, given today's economic 
conditions. Briefly, that estimate involved collecting the price 
expectations that presumably drive current investment decisions, some 
based on little or no royalty obligations, and then finding the 
increases from those prices that match the economic effect of forgiving 
royalties with reference to the minimum economic field size. Price 
thresholds of about 10 percent below the ones set in the Act result 
from this exercise.
    Several respondents also commented that regardless of the size of 
the price thresholds, our policy should be that production does not 
count against any remaining RS volume when it occurs during a period 
when prices exceed the threshold. But, this is contrary to the reason 
for having the thresholds in the first place. That is, at sufficiently 
high prices, the benefits on revenue preclude the need for relief on 
this production. If this production does not count against the RS 
volume, the production at high prices and profits that fully replace 
the royalty relief gets, in effect, a double incentive.
    We have clarified the price threshold language to make it more 
consistent with the application of the price threshold trigger and 
collection logistics mandated previously by Congress in the Act. The 
proposed rule intended maximum flexibility in the timing of the 
threshold and the collection of royalty by leaving the details for 
inclusion in future notices of sale. The final rule mimics the previous 
threshold rule except it does not adopt the calendar year as the time 
period for always calculating the price threshold. Rather, it allows 
some flexibility for a different time period. We retain the NYMEX as 
the pricing benchmark and the royalty collection process after the 
fixed price threshold time period.

Bidding Rules

    We did not ask for comments on our bidding policy rules because we 
are not proposing to change them. Nevertheless, we received comments on 
2 issues--prohibition of agreements after a lease sale and use of 
multiple bidding systems and variables--that deserve response.
    The intent of Sec. 260.303(d) is not to prevent restricted bidders 
from entering into agreements after we award a lease. Rather, 
subsection (d) prohibits pre-sale agreements between restricted bidders 
whereby one restricted bidder would commit to assigning part of a lease 
to another restricted bidder after the sale is completed. Specifically, 
subsection (d) prohibits restricted bidders A and B from entering into 
an agreement prior to a lease sale. The reason for this prohibition is 
to eliminate pre-sale agreements that might cause A to bid on a tract, 
and implicitly keep B from bidding, or cause B to submit a low bid 
because, if successful, A may assign a part of the lease to B. The 
current regulations at Sec. 260.303(c) already prohibit pre-bid 
agreements between restricted joint bidders. However, to clarify the 
intent of the new subsection (d), the phrase ``prior to a lease sale'' 
is inserted after the word ``agreement.''
    The first sentence in Sec. 260.110 makes it clear that we will 
apply a single bidding system and variable to each tract in a lease 
sale. However, we do intend to use multiple systems in a single sale, 
for instance offering some tracts with a royalty suspension and others 
with no royalty suspension, as we have for the last 5 years.

Procedural Matters

Regulatory Planning and Review (Executive Order 12866)

    According to the criteria in Executive Order 12866, this rule is a 
significant regulatory action. The Office of Management and Budget 
(OMB) makes the final determination under Executive Order 12866.
    a. This rule will not have an annual economic effect of $100 
million or adversely affect an economic sector, jobs, the environment, 
or other units of government. This action is a plain-language rewrite 
of current rules and clarification of policies that may be employed for 
issuing leases with royalty suspensions in lease sales held after 
November 2000. There is no assurance that the leasing system option 
provided in this rule will be used in all future offshore sales. For 
instance, sustained high prices or a shortage of unleased tracts may 
cause us to discontinue leasing incentives. Even when used, the leasing 
system option in this rule will not change substantially the net 
economic value of production from leases eligible for royalty 
suspension volumes. Royalty suspension should lead to higher bonuses 
because future production will be more profitable. Also, more tracts 
should receive bids because royalty relief makes smaller, more remote 
fields potentially profitable. But, because the government collects the 
fair market value of a tract in the up-front bid, the risk that the 
tract will not prove productive is shifted entirely to the bidder. We 
do not expect bonus bids to offset fully the anticipated royalty 
savings on a specific tract. Since these offsetting effects on revenue 
will play out over an extended period and involve uncertainties that 
will be assessed differently by the different bidders, we cannot 
predict the ultimate effect on government receipts. Most of the more 
prospective tracts have been leased already and the incentives we 
envision for the next several years are smaller than those mandated by 
the Act. Thus, we don't expect to see the level of bidding activity 
experienced in the last 5 years, nor the same level of future royalty 
reduction. At this point we can say that deep water royalty relief will 
serve primarily to accelerate the timing of production and redistribute 
realization of fair market value from royalty to bonus collection. As 
royalty suspension volumes are an incentive to production, they likely 
encourage timely exploration in hope of finding reserves, since royalty 
relief has no value unless and until production occurs. This 
acceleration will have a beneficial effect on offshore oil industry 
production and jobs in the near term.
    b. This rule will not create inconsistencies with other agencies' 
actions because there are no changes in requirements from the existing 
rule.
    c. This rule is an administrative change that will not affect 
entitlements, grants, user fees, loan programs, or their recipients. 
This rule has no effect on these programs or rights of the programs' 
recipients.
    d. This rule will raise novel legal or policy issues. Although this 
action is basically the rewrite of an existing rule in plain language 
and sets up a more flexible framework to continue current royalty 
suspension policies for future sales, it comes at a time when oil and 
gas prices are unusually high. Some may question the need to continue 
leasing incentives. We believe royalty suspension remains necessary in 
a scaled-down and more flexible format because prices can fall as well 
as rise. Also, a continued program reduces disruptions associated with 
an abrupt termination of incentives and resultant pressure to continue 
the rigid, outdated, and expiring terms of the Act.

Regulatory Flexibility (RF) Act

    The Department certifies that this rule would not have a 
significant economic effect on a substantial number of small entities 
under the RF Act (5 U.S.C. 601 et seq.). The provisions of this rule 
will not have a significant economic effect on offshore lessees and 
operators, including those that are classified as small businesses. The 
rule will authorize royalty relief to certain OCS leases awarded in 
sales held after November 2000. New regulatory provisions will offer 
firms, large and small, economic incentives to acquire

[[Page 11516]]

and develop deep water leases in the GOM.
    Companies that extract oil, gas, or natural gas liquids or are 
otherwise in oil and gas exploration and development activities acquire 
the vast majority of leases offered at OCS lease sales and will be most 
affected by this rule. The Small Business Administration (SBA) defines 
a small business as having:
    <bullet> Annual revenues of $5 million or less for exploration 
service and field service companies.
    <bullet> Fewer than 500 employees for drilling companies and for 
companies that extract oil, gas, or natural gas liquids.
    Under the North American Industry Classification System Code, 
211111, Crude Petroleum and Natural Gas Extraction, MMS estimates that 
a total of 1,380 firms drill oil and gas wells onshore and offshore. 
The group most affected by this rule is the approximately 130 companies 
that are offshore lessees/operators. According to SBA criteria, 39 
companies qualify as large firms, leaving up to 91 companies that may 
qualify as small firms with fewer than 500 employees. However, because 
of the extremely high cost and technical complexity involved in 
exploration and development in deep water, the vast majority of 
lessees/operators that will be affected by this rule will be large 
companies. Nineteen of the 26 lessee/operators that have registered a 
total of 211 discoveries by mid-year 2000 in deep water (200 meters and 
greater) are not small and these 19 large firms account for over 91 
percent of the total discoveries. The rule envisions limiting 
incentives to deep water where the presence of large firms is even more 
prevalent. Virtually all of the prospective tracts in the part of deep 
water where small firms traditionally operate are already under lease.
    This rule would add costs in two areas where there are no costs 
under the existing rules and the deep water royalty relief terms 
associated with eligible leases. First, lease terms for eligible leases 
suspended all payments, including rents and minimum royalties, after 
start of production on the lease and until the mandated royalty 
suspension volumes were fully produced. This rule would require that 
lessees of leases issued in sales after the effective date of this rule 
must continue to make annual rental payments after a discovery. Rental 
payments will be due during any year after discovery when no royalty 
payments are due. Rentals would replace minimum royalties between 
discovery and start of production for those leases. Experience to date 
(mid-2000) shows that only four leases are actually producing under the 
royalty suspension terms set by the Act. Both of the two operators 
involved happen to be small businesses. If that experience continues 
for leases issued after this rule, we might expect that perhaps one 
such lease may produce by 2004, and two more might produce by 2005. 
Thus, these new leases, irrespective of the size of the lessee, may pay 
extra rentals ($43,200/lease/year) of $172,800, or an average over the 
next 5 years of just below $35,000/year. This estimate presumes that 
these leases will pay rentals instead of ``minimum royalties'' between 
discovery and start of production.
    Second, the rule would add the requirement that owners of eligible 
leases notify MMS prior to initiating production on the leases. We 
estimate it will take an operator one-half hour to draft, finalize, and 
send such a notification letter. We envision that this letter will be 
very brief and give only pertinent data such as lease number, area/
block, date production is scheduled to commence, and language 
requesting confirmation of the amount of royalty relief applicable. We 
currently have six eligible leases with approved Development Operations 
Coordination Documents (DOCD) and 264 eligible leases with approved 
Plans of Exploration (POE). For this analysis, we assume that:
    (1) All six leases with approved DOCDs will commence production 
within the first 5 years;
    (2) Thirty percent (79) of the 264 leases with approved POEs will 
drill a discovery well; and
    (3) Twenty-five percent (20) of those leases with a discovery well 
will obtain a DOCD and commence production. Based on these assumptions, 
we estimate that a total of 26 eligible leases will commence production 
within the next 5 years.
    At an estimated paperwork cost of $50 per hour or $25 per 
notification, the total estimated cost of the notification requirement 
for the first 5 years in which the rule is in effect is $650 or $130 
per year.
    Thus, total estimated incremental costs associated with this rule 
are slightly below $35,000 per year on average through 2005. The annual 
cost will be spread among lessees whose eligible leases commence 
production and eventually among leases issued after this rule becomes 
effective and that produce with a royalty suspension. Based on the 
ratios found above, small business may incur one-tenth to one-third of 
this incremental cost. The annual cost for a small business with a 
lease producing under royalty suspension but paying rental would be 
approximately $44,000 per year. Even if a small business has several 
eligible leases commencing production, it is clear that the magnitude 
of the costs do not impose a significant economic effect on a 
substantial number of small business entities engaged in multi-million 
dollar drilling and development activities.
    Further, any costs associated with the rule must be viewed in light 
of the substantial economic benefits to be gained from the suspension 
of royalty payments on the established volume of production. While 
estimated averaged annual costs are just under $35,000 per year through 
2005, lessees that produce stand to gain tens of millions of dollars in 
royalty relief from the rule. For example, the standard royalty portion 
(\1/8\) of a 9 MMBOE royalty suspension volume is worth $25 to $30 
million at current oil and gas prices. Again, small business may claim 
one-tenth to one-third of this benefit. The potential benefit of 
royalty relief to a small business can be as high as $10 million/year, 
several orders of magnitude above the extra cost/year under this rule 
for a small business operating in deep water.
    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 agency's responsiveness to small 
business. If you wish to comment on the enforcement actions of MMS, 
call toll-free (888) 734-3247.

Small Business Regulatory Enforcement Fairness Act (SBREFA)

    This rule is not a major rule under the SBREFA, 5 U.S.C. 804(2). 
This rule:
    a. Does not have an annual effect on the economy of $100 million or 
more. This rule rewrites the existing rule and clarifies royalty 
suspension policies for future sales. This rule does not specify exact 
royalty suspension parameters, but describes the structure that we will 
follow in applying sale-specific royalty suspensions to future leases. 
While royalty suspension volumes for future lease sales are not likely 
to be as high as the current levels specified in the Act, they will 
still provide meaningful benefits to large and small business lessees.
    In general, royalty suspension redistributes revenues--royalty 
payments decline during the royalty suspension period, while bonus

[[Page 11517]]

payments before exploration and tax payments due on extra income to the 
lessee during the royalty suspension period increase. To benefit from 
the royalty suspension, the lease must produce. Because only a fraction 
of tracts leased ultimately produce oil and gas, a relatively small 
number of tracts actually receive a royalty suspension. To determine 
the annual effect of the royalty relief system on the economy, both the 
effects on bonus bids and future royalties need to be considered. 
Experience from sales (during the 1983 to 1988 period) where leases 
have had time to run the course of the original lease term show that, 
on average, only about 15 percent of leases issued go into production. 
Also, estimates for sales between 1996 and 2000 suggest that bidders 
bid about a $500,000 premium per royalty suspension lease. Using a 
ratio of seven leases issued for every one (15 percent) that produces, 
the Government can expect to collect perhaps $3.5 million in extra 
bonus revenues for each lease that uses a royalty suspension. That 
extra bonus will be offset by collection of about $22.5 million less in 
royalties (e.g., \1/8\ of 9 MMBOE times $20/BOE over the production 
period (e.g., 2010 to 2020). If extra taxes reclaim about \1/3\ of the 
royalty cost savings, those are comparable sums on a present value 
basis (e.g., 7  x  $0.5 approximately = $20 (1\1/3\  x  0.26 where 0.26 
is a discount factor for payments received 10 to 20 years in the 
future). Thus, even when scaled up to cover sales of hundreds of leases 
in any one year, this rule will not have an annual effect on the 
economy of $100 million or more.
    b. Will not cause a major increase in costs or prices for 
consumers, individual industries, Federal, State, or local government 
agencies, or geographic regions. Oil prices are not based on the 
production from any one region, but are based on worldwide production 
and demand at any point in time. While gas prices are more localized, 
they historically correlate to oil prices. The rule does not change any 
existing leasing policies, so it should not cause prices to increase.
    c. Does not have significant adverse effects on competition, 
employment, investment, innovation, or the ability of United States-
based enterprises to compete with foreign-based enterprises. Leasing on 
the United States OCS is limited to entities as specified in 30 CFR 
256.35. This rule does not change that requirement, so it does not 
change the ability of United States firms to compete in any way.

Unfunded Mandates Reform Act (UMRA)

    This rule does not impose an unfunded mandate on State, local, or 
tribal governments or the private sector of more than $100 million per 
year. The rule does not have a significant or unique effect on State, 
local, or tribal governments. The rule describes the existing 
regulation in plain language and clarifies royalty suspension policies 
for OCS lease sales held after November 2000. A statement containing 
additional UMRA (2 U.S.C. 1531 et seq.) information is not required.

Takings Implications Assessment (Executive Order 12630)

    According to Executive Order 12630, the rule does not have 
significant Takings Implications. A Takings Implication Assessment is 
not required because the rule would not take away or restrict a 
bidder's right to acquire OCS leases.

Federalism (Executive Order 13132)

    According to Executive Order 13132, this rule does not have 
Federalism implications. This rule does not substantially and directly 
affect the relationship between the Federal and State Governments. This 
rule affects the collection of royalty revenues and rentals from 
lessees in the deep water GOM, all of which are outside State 
jurisdiction. States have no role in this activity with or without this 
rule. This rule does not impose costs on States or localities. States 
and local governments play no part in the administration of the deep 
water royalty relief or rental programs.

Civil Justice Reform (Executive Order 12988)

    According to Executive Order 12988, the Office of the Solicitor has 
determined that this rule does not unduly burden the judicial system 
and meets the requirements of sections 3(a) and 3(b)(2) of the Order.

Paperwork Reduction Act (PRA) of 1995

    According to the PRA (44 U.S.C. 3501 et seq.), as part of the 
Notice of Proposed Rulemaking process, OMB approved the collection of 
information in the proposed regulations and assigned OMB control number 
1010-0143. We did not receive any comments opposing the information 
collection aspects of the proposed rule, and the final rule makes no 
change in the information collection requirements. The PRA provides 
that an agency may not conduct or sponsor, and a person is not required 
to respond to, a collection of information unless it displays a 
currently valid OMB control number.
    The title of the collection of information for this rule is ``30 
CFR Part 260--Outer Continental Shelf Oil and Gas Leasing.'' The 
requirement to respond is required to obtain or retain a benefit. The 
information collection requirements and estimated burdens are:
    (1) In Sec. 260.114(c), respondents must notify MMS of their 
intention to begin production, and they must request confirmation of 
the size of the royalty suspension volume that applies to their 
eligible lease. We estimate the burden to be one-half hour per 
notification, and that we would receive five-to-six notices annually.
    (2) In Secs. 260.114 and 260.124, there is a provision for a lessee 
or other affected lessees to request reconsideration of MMS's 
assignment of a lease that has a qualifying well to an existing field 
or designate a new field. We estimate the burden can range between 80 
and 1,000 hours per request for reconsideration. That wide range 
reflects the fact that fields can underlie from 1 to more than 10 
leases, can include from 1 to several dozen reservoirs, or can require 
simple to complex geological and geophysical interpretations. Because a 
favorable field assignment can save a lessee tens of millions of 
dollars in royalties, we may get as many simple as complex appeals. For 
purposes of estimating burden, we assume that we receive three or four 
annually, uniformly spread over the simple to complex range with an 
average burden of 400 hours.
    We estimate the total annual reporting ``hour'' burden for the 30 
CFR part 260 regulations to be about 1,600 hours. This includes the 
time for reviewing instructions, searching existing data sources, and 
gathering the data. There are no recordkeeping requirements.

National Environmental Policy Act (NEPA) of 1969

    This rule does not constitute a major Federal action significantly 
affecting the quality of the human environment. A detailed statement 
under the NEPA is not required.

Government-to-Government Relationship with Tribes

    According to the President's memorandum of April 29, 1994, 
``Government-to-Government Relations with Native American Tribal 
Governments'' (59 FR 22951) and 512 DM 2, we have determined that there 
are no effects from this action on federally recognized Indian tribes.

[[Page 11518]]

List of Subjects

30 CFR Part 218

    Continental shelf, Methods of payment, Mineral royalties, Public 
lands--Mineral resources, Royalty payments. Net profit share payment, 
Rental payments.

30 CFR Part 256

    Administrative practice and procedure, Continental shelf, 
Environmental protection, Government contracts, Mineral royalties, Oil 
and gas exploration, Pipelines, Public lands--mineral resources, Public 
lands--rights-of-way, Reporting and recordkeeping requirements, Surety 
bonds.

30 CFR Part 260

    Bidding system, Continental shelf, mineral royalties, Oil and gas 
leasing, Reporting requirements, Restricted joint bidder, Royalty 
suspension.

    Dated: February 16, 2001.
Piet deWitt,
Assistant Secretary, Land and Minerals Management.

    For the reasons stated in the preamble, the Minerals Management 
Service (MMS) amends 30 CFR parts 218, 256, and 260 as follows:

PART 218--COLLECTION OF ROYALTIES, RENTALS, BONUSES AND OTHER 
MONIES DUE THE FEDERAL GOVERNMENT

    1. The authority citation for part 218 continues to read as 
follows:

    Authority: 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.A. 3335; 43 U.S.C. 1301 et seq., 1331 et seq., 1801 et seq.


    2. In Sec. 218.151, the section heading is revised, an introductory 
paragraph is added, paragraphs (a) and (b) are revised; paragraphs (c) 
and (d) are removed; and paragraph (e) is redesignated as paragraph (c) 
to read as follows:


Sec. 218.151  Rental Fees.

    The annual rental paid in any year is in addition to, and is not 
credited against, any royalties due from production. The lessee must 
pay an annual rental as shown in paragraphs (a), (b), and (c) of this 
section. Discovery means one or more wells on the lease that meet the 
requirements in 250, subpart A of this title.
    (a) This paragraph applies to any lease not covered by paragraph 
(b) or paragraph (c) of this section.

------------------------------------------------------------------------
                                   Issued as a
             For--               result of a sale   The lessee must pay
                                      held--              rental--
------------------------------------------------------------------------
(1) An oil and gas lease......  Before March 26,   On or before the
                                 2001.              first day of each
                                                    lease year before
                                                    the discovery of oil
                                                    or gas on the lease.
(2) An oil and gas lease......  After March 26,    On or before the
                                 2001.              first day of each
                                                    lease year before
                                                    the discovery of oil
                                                    or gas on the lease,
                                                    then on or before
                                                    the last day of each
                                                    lease year in any
                                                    full year in which
                                                    royalties on
                                                    production are not
                                                    due.
(3) A mineral lease for other   Before March 26,   On or before the
 than oil or gas.                2001.              first day of each
                                                    lease year before
                                                    the discovery of
                                                    paying quantities.
(4) A mineral lease for other   After March 26,    On or before the
 than oil or gas.                2001.              first day of each
                                                    lease year before
                                                    the date the first
                                                    royalty payment is
                                                    due on the lease,
                                                    then on or before
                                                    the last day of each
                                                    lease year in any
                                                    full year in which
                                                    royalties on
                                                    production are not
                                                    due.
------------------------------------------------------------------------

    (b) This paragraph applies to any lease created by segregating a 
portion of a producing lease when there is no actual or allocated 
production on the segregated portion. The lessee must pay an annual 
rental for the segregated portion at the rate specified in the lease. 
The lessee must pay the rental as shown in the following table.

------------------------------------------------------------------------
 If the lease results from a
        segregation--                 The lessee must pay rental--
------------------------------------------------------------------------
(1) Before March 26, 2001....  On or before the first day of each lease
                                year before the discovery of oil or gas
                                on the segregated portion.
(2) After March 26, 2001.....  On or before the first day of each lease
                                year before the discovery of oil or gas
                                on the lease, then on or before the last
                                day of each lease year in any full year
                                in which royalties on production are not
                                due.
------------------------------------------------------------------------

    (c) * * *

PART 256--LEASING OF SULPHUR OR OIL AND GAS IN THE OUTER 
CONTINENTAL SHELF

    3. The authority citation for part 256 continues to read as 
follows:

    Authority: 42 U.S.C. 6213 and 43 U.S.C. 1331, et seq.


    4. In Sec. 256.40, the introductory paragraph is revised to read as 
follows:


Sec. 256.40  Definitions

    The following definitions apply to Secs. 256.38 through 256.44 of 
this part.
* * * * *

    5. Part 260 is revised to read as follows:

PART 260--OUTER CONTINENTAL SHELF OIL AND GAS LEASING

Subpart A--General Provisions
Sec.
260.1   What is the purpose of this part?
260.2   What definitions apply to this part?
260.3   What is MMS's authority to collect information?
Subpart B--Bidding Systems
260.101   What is the purpose of this subpart?
260.102   What definitions apply to this subpart?
260.110   What bidding systems may MMS use?
260.111   What conditions apply to the bidding systems that MMS 
uses?

Eligible Leases

260.112  How do royalty suspension volumes apply to eligible leases?
260.113   When does an eligible lease qualify for a royalty 
suspension volume?
260.114   How does MMS assign and monitor royalty suspension volumes 
for eligible leases?
260.115   How long will a royalty suspension volume for an eligible 
lease be effective?
260.116   How do I measure natural gas production on my eligible 
lease?
260.117   What other provisions apply to royalty suspension volumes 
for eligible leases?

Royalty Suspension (RS) Leases

260.120  How does royalty suspension apply to leases issued in a 
sale held after November 2000?

[[Page 11519]]

260.121   When does a lease issued in a sale held after November 
2000 get a royalty suspension?
260.122   How long will a royalty suspension volume be effective for 
a lease issued in a sale held after November 2000?
260.123   How do I measure natural gas production for a lease issued 
in a sale held after November 2000?
260.124   How will royalty suspension apply if MMS assigns a lease 
issued in a sale held after November 2000 to a field that has an 
eligible or pre-Act lease?

Bidding System Selection Criteria

260.130  What criteria does MMS use for selecting bidding systems 
and bidding system components?
Subpart C [Reserved]
Subpart D--Joint Bidding
260.301  What is the purpose of this subpart?
260.302   What definitions apply to this subpart?
260.303   What are the joint bidding requirements?

    Authority: 43 U.S.C. 1331 et seq.

Subpart A--General Provisions


Sec. 260.1  What is the purpose of this part?

    Part 260 implements the Outer Continental Shelf Lands Act (OCSLA), 
43 U.S.C. 1331 et seq., as amended, by providing regulations to foster 
competition including, but not limited to:
    (a) Implementing alternative bidding systems;
    (b) Prohibiting joint bidding for development rights by certain 
types of joint ventures; and
    (c) Establishing diligence requirements for Federal OCS leases.


Sec. 260.2  What definitions apply to this part?

    OCS lease means a Federal lease for oil and gas issued under the 
OCSLA.
    OCSLA means the Outer Continental Shelf Lands Act, (43 U.S.C. 1331 
et seq.), as amended.
    Person includes, in addition to a natural person, an association, a 
State, or a private, public, or municipal corporation.
    We means the Minerals Management Service (MMS).
    You means the lessee or operating rights holder.


Sec. 260.3  What is MMS's authority to collect information?

    The Paperwork Reduction Act of 1995 (PRA) requires us to inform you 
that we may not conduct or sponsor and you are not required to respond 
to a collection of information unless it displays a currently valid OMB 
control number. OMB approved the information collection requirements in 
part 260 under 44 U.S.C. 3501 et seq. and assigned OMB control number 
1010-0143. The PRA also requires us to inform you of the following:
    (a) We use the information collected under Secs. 260.114(a)(2), 
(c)(1) and 260.124 (a)(2):
    (1) To make decisions on requests for reconsideration of our 
assignment of a lease that has a qualifying well to an existing field 
or designate a new field under Secs. 260.114(a) and 260.124(a), and
    (2) To ensure that the royalty suspension volume is properly 
allocated among constituent leases in a field under Sec. 260.117.
    (b) Respondents are Federal OCS oil and gas lessees and operating 
rights holders. Responses are required to obtain or retain a benefit. 
We will protect proprietary information under applicable law and part 
250 of this chapter.
    (c) You may send comments regarding any aspect of the collection of 
information under this part, including suggestions for reducing the 
burden, to the Information Collection Clearance Officer, Minerals 
Management Service, Mail Stop 4230, 1849 C Street, NW., Washington, DC 
20240.

Subpart B--Bidding Systems

General Provisions


Sec. 260.101  What is the purpose of this subpart?

    This subpart establishes the bidding systems that we may use to 
offer and sell Federal leases for the exploration, development, and 
production of oil and gas resources located on the OCS.


Sec. 260.102  What definitions apply to this subpart?

    Act means the Outer Continental Shelf Deep Water Royalty Relief 
Act, Pub. L. 104-58, 43 U.S.C. 1337(3).

    Eligible lease means a lease that:
    (1) Is issued as part of an OCS lease sale held after November 28, 
1995, and before November 28, 2000;
    (2) Is located in the Gulf of Mexico in water depths of 200 meters 
or deeper;
    (3) Lies wholly west of 87 degrees, 30 minutes West longitude; and
    (4) Is offered subject to a royalty suspension volume.
    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. Two or more 
reservoirs may be in a field, separated vertically by intervening 
impervious strata, or laterally by local geologic barriers, or by both.
    Highest responsible qualified bidder means a person who has met the 
appropriate requirements of 256, subpart G of this title, and has 
submitted a bid higher than any other bids by qualified bidders on the 
same tract.
    Highest royalty rate means the highest percent rate payable to the 
United States, as specified in the lease, in the amount or value of the 
production saved, removed, or sold.
    Lease period means the time from lease issuance until 
relinquishment, expiration, or termination.
    Lowest royalty rate means the lowest percent rate payable to the 
United States, as specified in the lease, in the amount or value of the 
production saved, removed, or sold.
    OCS lease sale means the Department of the Interior (DOI) 
proceeding by which leases for certain OCS tracts are offered for sale 
by competitive bidding and during which bids are received, announced, 
and recorded.
    Pre-Act lease means a lease that:
    (1) Is issued as part of an OCS lease sale held before November 28, 
1995;
    (2) Is located in the Gulf of Mexico in water depths of 200 meters 
or deeper; and
    (3) Lies wholly west of 87 degrees, 30 minutes West longitude. (See 
part 203 of this title.)
    Production period means the period during which the amount of oil 
and gas produced from a tract (or, if the tract is unitized, the amount 
of oil and gas as allocated under a unitization formula) will be 
measured for purposes of determining the amount of royalty payable to 
the United States
    Qualified bidder means a person who has met the appropriate 
requirements of Sec. 256, subpart G of this title.
    Royalty rate means the percentage of the amount or value of the 
production saved, removed, or sold that is due and payable to the 
United States Government.
    Royalty suspension (RS) lease means a lease that:
    (1) Is issued as part of an OCS lease sale held after November 28, 
2000;
    (2) Is in locations or planning areas specified in a particular 
Notice of OCS Lease Sale; and
    (3) Is offered subject to a royalty suspension specified in a 
Notice of OCS Lease Sale published in the Federal Register.
    Tract means a designation assigned solely for administrative 
purposes to a block or combination of blocks that are identified by a 
leasing map or an official protraction diagram prepared by the DOI.
    Value of production means the value of all oil and gas production 
saved, removed, or sold from a tract (or, if the tract is unitized, the 
value of all oil and

[[Page 11520]]

gas production saved, removed, or sold and credited to the tract under 
a unitization formula) during a period of production. The value of 
production is determined under part 206 of this title.


Sec. 260.110  What bidding systems may MMS use?

    We will apply a single bidding system selected from those listed in 
this section to each tract included in an OCS lease sale. The following 
table lists bidding systems, the bid variables, and characteristics.

----------------------------------------------------------------------------------------------------------------
        For the bidding system--                The bid variable is the--         And the characteristics are--
----------------------------------------------------------------------------------------------------------------
(a) Cash bonus bid with a fixed royalty   Cash bonus..........................  The highest responsible
 rate of not less than 12.5 percent.                                             qualified bidder will pay a
                                                                                 royalty rate of not less than
                                                                                 12.5 percent at the beginning
                                                                                 of the lease period. We will
                                                                                 specify the royalty rate for
                                                                                 each tract offered in the
                                                                                 Notice of OCS Lease Sale
                                                                                 published in the Federal
                                                                                 Register.
----------------------------------------------------------------------------------------------------------------
(b) Royalty rate bid with fixed cash      Royalty rate........................  We will specify the fixed amount
 bonus.                                                                          of cash bonus the highest
                                                                                 responsible qualified bidder
                                                                                 must pay in the Notice of OCS
                                                                                 Lease Sale published in the
                                                                                 Federal Register.
----------------------------------------------------------------------------------------------------------------
(c) Cash bonus bid with a sliding         Cash bonus..........................  (1) We will calculate the
 royalty rate of not less than 12.5                                              royalty rate the highest
 percent at the beginning of the lease                                           responsible qualified bidder
 period.                                                                         must pay using either:
                                                                                (i) A sliding-scale formula,
                                                                                 which relates the royalty rate
                                                                                 to the adjusted value or volume
                                                                                 of production, or (ii) A
                                                                                 schedule that establishes the
                                                                                 royalty rate that we will apply
                                                                                 to specified ranges of the
                                                                                 adjusted value or volume of
                                                                                 production.
                                                                                (2) We will determine the
                                                                                 adjusted value of production by
                                                                                 applying an inflation factor to
                                                                                 the actual value of production.
                                                                                (3) If you are the successful
                                                                                 high bidder, your lease will
                                                                                 include the sliding-scale
                                                                                 formula or schedule and will
                                                                                 specify the lowest and highest
                                                                                 royalty rates that will apply.
                                                                                (4) You will pay a royalty rate
                                                                                 of not less than 12.5 percent
                                                                                 at the beginning of the lease
                                                                                 period.
                                                                                (5) We will include the sliding-
                                                                                 scale royalty formula or
                                                                                 schedule, inflation factor and
                                                                                 procedures for making the
                                                                                 inflation adjustment and
                                                                                 determining the value or amount
                                                                                 of production in the Notice of
                                                                                 OCS Lease Sale published in the
                                                                                 Federal Register.
----------------------------------------------------------------------------------------------------------------
(d) Cash bonus bid with fixed share of    Cash bonus..........................  (1) If we award you a lease as
 the net profits of no less than 30                                              the highest responsible
 percent.                                                                        qualified bidder, you will
                                                                                 determine the amount of the net
                                                                                 profit share payment to the
                                                                                 United States for each month by
                                                                                 multiplying the net profit
                                                                                 share base times the net profit
                                                                                 share rate, according to Sec.
                                                                                 220.022. You will calculate the
                                                                                 net profit share base according
                                                                                 to Sec.  220.021.
                                                                                (2) You will pay a net profit
                                                                                 share of not less than 30
                                                                                 percent.
                                                                                (3) We will specify the capital
                                                                                 recovery factor, as described
                                                                                 in Sec.  220.020, and the net
                                                                                 profit share rate, both of
                                                                                 which may vary from tract to
                                                                                 tract, in the Notice of OCS
                                                                                 Lease Sale published in the
                                                                                 Federal Register.
----------------------------------------------------------------------------------------------------------------
(e) Cash bonus with variable royalty      Cash bonus..........................  (1) We may suspend or defer
 rate(s) during one or more periods of                                           royalty for a period, volume,
 production.                                                                     or value of production.
                                                                                 Notwithstanding suspensions or
                                                                                 deferrals, we may impose a
                                                                                 minimum royalty. The
                                                                                 suspensions or deferrals may
                                                                                 vary based on prices or price
                                                                                 changes of oil and/or gas.
                                                                                (2) You may pay a royalty rate
                                                                                 less than 12.5 percent on
                                                                                 production but not less than
                                                                                 zero percent.
                                                                                (3) We will specify the
                                                                                 applicable royalty rates(s) and
                                                                                 suspension or deferral
                                                                                 magnitudes, formulas, or
                                                                                 relationships in the Notice of
                                                                                 OCS Lease Sale published in the
                                                                                 Federal Register.
----------------------------------------------------------------------------------------------------------------
(f) Cash bonus with royalty rate(s)       Cash bonus..........................  We will base the royalty rate on
 based on formula(s) or schedule(s)                                              formula(s) or schedule(s)
 during one or more periods of                                                   specified in the Notice of OCS
 production.                                                                     Lease Sale published in the
                                                                                 Federal Register.
----------------------------------------------------------------------------------------------------------------
(g) Cash bonus with a fixed royalty rate  Cash bonus..........................  Except for periods of royalty
 of not less than 12.5 percent, at the                                           suspension, you will pay a
 beginning of the lease period,                                                  fixed royalty rate of not less
 suspension of royalties for a period,                                           than 12.5 percent. If we award
 volume, or value of production, or                                              to you a lease under this
 depending upon selected characteristics                                         system, you must calculate the
 of extraction, and with suspensions                                             royalty due during the
 that may vary based on the price of                                             designated period using the
 production.                                                                     rate, formula, or schedule
                                                                                 specified in the lease. We will
                                                                                 specify the royalty rate,
                                                                                 formula, or schedule in the
                                                                                 Notice of OCS Lease Sale
                                                                                 published in the Federal
                                                                                 Register.
----------------------------------------------------------------------------------------------------------------


[[Page 11521]]

Sec. 260.111  What conditions apply to the bidding systems that MMS 
uses?

    (a) For each of the bidding systems in Sec. 260.110, we will 
include an annual rental fee. Other fees and provisions may apply as 
well. The Notice of OCS Lease Sale published in the Federal Register 
will specify the annual rental and any other fees the highest 
responsible qualified bidder must pay and any other provisions.
    (b) If we use any deferment or schedule of payments for the cash 
bonus bid, we will specify and include it in the Notice of OCS Lease 
Sale published in the Federal Register.
    (c) For the bidding systems listed in this subpart, if the bid 
variable is a cash bonus bid, the highest bid by a qualified bidder 
determines the amount of cash bonus to be paid. We will include the 
minimum bid level(s) in the Notice of OCS Lease Sale published in the 
Federal Register.
    (d) For the bidding systems listed in this subpart, if the bid 
variable is the royalty rate, the highest bid by a qualified bidder 
determines the royalty rate to be paid. We will include the minimum 
royalty rate(s) in the Notice of OCS Lease Sale published in the 
Federal Register.
    (e) We may, by rule, add to or modify the bidding systems listed in 
Sec. 260.110, according to the procedural requirements of the OCSLA, 43 
U.S.C. 1331 et seq., as amended by Public Law 95-372, 92 Stat. 629.

Eligible Leases


Sec. 260.112  How do royalty suspension volumes apply to eligible 
leases?

    Royalty suspension volumes, as specified in section 304 of the Act, 
apply to eligible leases that meet the criteria in Sec. 260.113. For 
purposes of this section and Secs. 260.113 through 260.117:
    (a) Any volumes of production that are not normally royalty-bearing 
under the lease or the regulations (e.g., fuel gas) do not count 
against royalty suspension volumes; and
    (b) Production includes volumes allocated to a lease under an 
approved unit agreement.


Sec. 260.113  When does an eligible lease qualify for a royalty 
suspension volume?

    (a) Your eligible lease may receive a royalty suspension volume 
only if it is in a field where no current lease produced oil or gas 
(other than test production) before November 28, 1995. For eligible 
leases, the bidding system in Sec. 260.110(g) applies only to leases in 
fields that meet this condition.
    (b) 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 that meridian will receive a royalty suspension 
volume only for those eligible leases lying entirely west of the 
meridian.


Sec. 260.114  How does MMS assign and monitor royalty suspension 
volumes for eligible leases?

    (a) We will assign your lease that has a qualifying well (under 
part 250, subpart A of this title) to an existing field or designate a 
new field and will notify you and other affected lessees and operating 
rights holders in the field of that assignment.
    (1) Within 15 days of that notification, you or any of the other 
affected lessees or operating rights holders may file a written request 
with the Director of MMS (Director) for reconsideration accompanied by 
a ``Statement of Reasons.''
    (2) The Director will respond in writing either affirming or 
reversing the assignment decision. The Director's decision is the final 
action of the Department of the Interior and is not subject to appeal 
to the Interior Board of Land Appeals under part 290 of this title and 
43 CFR part 4.
    (b) We have specified the water depth for each eligible lease in 
the final Notice of OCS Lease Sale. Our determination of water depth 
for each lease is final once we issue the lease. We have specified in 
the Notice the royalty suspension volume applicable to each water 
depth. The minimum royalty suspension volumes for fields in million 
barrels of oil equivalent (MMBOE) are shown in the following table:

------------------------------------------------------------------------
                                             Minimum royalty suspension
               Water depth                             volume
------------------------------------------------------------------------
(1) 200 to 400 meters....................  17.5 MMBOE
(2) 400 to 800 meters....................  52.5 MMBOE
(3) 800 meters or more...................  87.5 MMBOE
------------------------------------------------------------------------

    (c) Before commencing production, you must:
    (1) Notify the MMS Regional Supervisor for Production and 
Development of your intention to start production; and
    (2) Request confirmation of the size of the royalty suspension 
volume that applies to your eligible lease.
    (d) When production (other than test production) first occurs from 
any of the eligible leases in a field consisting only of eligible 
leases, we will determine what royalty suspension volume applies to the 
lease(s) in that field. We base the determination for eligible lease(s) 
on the royalty suspension volumes specified in paragraph (b) of this 
section and Sec. 260.117(a).
    (e) Your eligible 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 from another field, 
production from that new field receives a separate royalty suspension.


Sec. 260.115  How long will a royalty suspension volume for an eligible 
lease be effective?

    A royalty suspension volume for an eligible lease will continue 
through the end of the month in which cumulative production from the 
leases in a field entitled to share the royalty suspension volume 
reaches that volume or the lease period ends.


Sec. 260.116  How do I measure natural gas production on my eligible 
lease?

    You must measure natural gas production on your eligible lease 
subject to the royalty suspension volume as follows: 5.62 thousand 
cubic feet of natural gas, measured according to part 250, subpart L of 
this title, equals one barrel of oil equivalent.


Sec. 260.117  What other provisions apply to royalty suspension volumes 
for eligible leases?

    In addition to the provisions in Secs. 260.111 through 260.116, the 
provisions in this section apply to royalty suspension volumes on 
eligible leases.
    (a) If a new field consists of eligible leases in different water-
depth categories, the royalty suspension volume associated with the 
eligible lease in the deepest water applies.
    (b) 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.
    (c) If a field consists of more than one eligible lease:
    (1) Payment of royalties on the eligible leases' initial production 
is suspended until cumulative production equals the field's established 
royalty suspension volume;
    (2) Only production from leases entitled to share in the field's 
royalty suspension volume counts as part of this cumulative production; 
and
    (3) 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 royalty suspension volume is 
reached.
    (d) This paragraph applies if we add an eligible lease to a field 
that has an established royalty suspension volume

[[Page 11522]]

that we approved under part 203 of this title. This paragraph also 
applies to a field that has an established royalty suspension volume as 
a result of production starting from one or more eligible leases in the 
field. In situations covered by this paragraph:
    (1) The field's royalty suspension volume will not change, even if 
the added lease is in deeper water;
    (2) If we granted a royalty suspension volume under part 203 of 
this title that is larger than the minimum specified for that water 
depth, the added eligible lease may share in the larger suspension 
volume;
    (3) The eligible lease may receive a royalty suspension volume only 
to the extent of its production before the cumulative production equals 
the field's previously established royalty suspension volume; and
    (4) Only production from leases entitled to share in the field's 
previously established royalty suspension volume counts as part of this 
cumulative production.
    (e) A pre-Act lease may receive a royalty suspension volume under 
part 203 of this title for a field that already has a royalty 
suspension volume due to eligible leases. If this happens, then:
    (1) The eligible and pre-Act leases share a single royalty 
suspension volume;
    (2) The field's royalty suspension volume is the larger of the 
volume for the eligible leases or the volume MMS grants in response to 
the pre-Act leases' application; and
    (3) The suspension volume for each eligible lease is its actual 
production from the lease until cumulative production from all leases 
in the field entitled to share in the field-based suspension volume 
equals the suspension volume.
    (f) If we reassign a well on an eligible lease to another field, 
the past production from that well:
    (1) Will count toward the royalty suspension volume, if any, 
specified for the field to which it is reassigned; and
     (2) Will not count toward the royalty suspension volume, if any, 
for the field from which it was reassigned.

Royalty Suspension (RS) Leases


Sec. 260.120  How does royalty suspension apply to leases issued in a 
sale held after November 2000?

    We may issue leases with suspension of royalties for a period, 
volume or value of production, as authorized in section 303 of the Act. 
For purposes of this section and Secs. 260.121 through 260.124:
    (a) Any volumes of production that are not normally royalty-bearing 
under the lease or the regulations (e.g., fuel gas) do not count 
against royalty suspension volumes; and
    (b) Production includes volumes allocated to a lease under an 
approved unit agreement.


Sec. 260.121  When does a lease issued in a sale held after November 
2000 get a royalty suspension?

    (a) We will specify any royalty suspension for your RS lease in the 
Notice of OCS Lease Sale published in the Federal Register for the sale 
in which you acquire the RS lease and will repeat it in the lease 
document. In addition:
    (1) Your RS lease may produce royalty-free the royalty suspension 
we specify for your lease, even if the field to which we assign it is 
producing.
    (2) The royalty suspension we specify in the Notice of OCS Lease 
Sale for your lease does not apply to any other leases in the field to 
which we assign your RS lease.
    (b) You may apply for a supplemental royalty suspension for a 
project under part 203 of this title, if your lease lies:
    (1) In the Gulf of Mexico,
    (2) In water 200 meters or deeper, and
    (3) Wholly west of 87 degrees, 30 minutes West longitude.
    (c) Your RS lease retains the royalty suspension with which we 
issued it even if we deny your application for more relief.


Sec. 260.122  How long will a royalty suspension volume be effective 
for a lease issued in a sale held after November 2000?

    (a) The royalty suspension volume for your RS lease will continue 
through the end of the month in which cumulative production from your 
lease reaches the applicable royalty suspension volume or the lease 
period ends.
    (b)(1) Notwithstanding any royalty suspension under this subpart, 
you must pay royalty at the lease stipulated rate on:
    (i) Any oil produced for any period stipulated in the lease during 
which the arithmetic average of the daily closing prices on the New 
York Mercantile Exchange (NYMEX) for light sweet crude oil exceeds a 
threshold price stipulated in the lease, or
    (ii) Any natural gas produced for any period stipulated in the 
lease during which the arithmetic average of the daily closing prices 
on the NYMEX for natural gas exceeds a threshold price stipulated in 
the lease.
    (2) You must pay any royalty due under this paragraph, plus late 
payment interest under Sec. 218.54 of this title, no later than 90 days 
after the end of the period for which royalty is owed.
    (3) Any production on which you must pay royalty under this 
paragraph will count toward the production volume determined under 
Secs. 260.120 through 260.124.
    (c) If you must pay royalty on any product (either oil or natural 
gas) for any period under paragraph (b), you must continue to pay 
royalty on that product during the next succeeding period of the same 
length until the arithmetic average of the daily closing NYMEX prices 
for that product for that period can be determined. If the arithmetic 
average of the daily closing prices for that product for that period is 
less than the threshold price stipulated in the lease, you are entitled 
to a credit or refund of royalties paid for that period with interest 
under applicable law.
    (d) MMS will adjust the threshold oil and gas prices referred to in 
paragraph (b) for any period stipulated in the lease by the percentage, 
if any, by which the implicit price deflator for the gross domestic 
product changed during the preceding period.


Sec. 260.123  How do I measure natural gas production for a lease 
issued in a sale held after November 2000?

    You must measure natural gas production subject to the royalty 
suspension volume for your lease as follows: 5.62 thousand cubic feet 
of natural gas, measured according to part 250, subpart L of this 
title, equals one barrel of oil equivalent.


Sec. 260.124  How will royalty suspension apply if MMS assigns a lease 
issued in a sale held after November 2000 to a field that has an 
eligible or pre-Act lease?

    (a) We will assign your lease that has a qualifying well (under 
part 250, subpart A of this title) to an existing field or designate a 
new field and will notify you and other affected lessees and operating 
rights holders in the field of that assignment.
    (1) Within 15 days of the final notification, you or any of the 
other affected lessees or operating rights holders may file a written 
request with the Director for reconsideration, accompanied by a 
Statement of Reasons.
    (2) The Director will respond in writing either affirming or 
reversing the assignment decision. The Director's decision is the final 
action of the Department of the Interior and is not subject to appeal 
to the Interior Board of Land Appeals under part 290 of this title and 
43 CFR part 4.
    (b) If we establish a royalty suspension volume for a field, either 
as a result of an approved application for royalty relief submitted for 
a pre-Act lease under part 203 of this title or as

[[Page 11523]]

the result of production starting from one or more eligible leases in 
the field, then:
    (1) Royalty-free production from your RS lease shares from and 
counts as part of any royalty suspension volume remaining for the field 
to which we assign your lease; and
    (2) Your RS lease may continue to produce royalty-free up to the 
royalty suspension we specified for your lease, even if the field to 
which we assign your RS lease has produced all of its royalty 
suspension volume.
    (c) Your lease may share in a suspension volume larger than the 
royalty suspension with which we issued it and to the extent we grant a 
larger volume in response to an application by a pre-Act lease 
submitted under part 203 of this title. To share in any larger royalty 
suspension volume, you must file an application described in 
Secs. 203.71 and 203.83. In no case will royalty-free production for 
your RS lease be less than the royalty suspension specified for your 
lease.

Bidding System Selection Criteria


Sec. 260.130  What criteria does MMS use for selecting bidding systems 
and bidding system components?

    In analyzing the application of one of the bidding systems listed 
in Sec. 260.110 to tracts selected for any OCS lease sale, we may, at 
our discretion, consider the following purposes and policies. We 
recognize that each of the purposes and policies may not be 
specifically applicable to the selection process for a particular 
bidding system or tract, or may present a conflict that we will have to 
resolve in the process of bidding system selection. The order of 
listing does not denote a ranking.
    (a) Providing fair return to the Federal Government;
    (b) Increasing competition;
    (c) Ensuring competent and safe operations;
    (d) Avoiding undue speculation;
    (e) Avoiding unnecessary delays in exploration, development, and 
production;
    (f) Discovering and recovering oil and gas;
    (g) Developing new oil and gas resources in an efficient and timely 
manner;
    (h) Limiting the administrative burdens on Government and industry; 
and
    (i) Providing an opportunity to experiment with various bidding 
systems to enable us to identify those most appropriate for the 
satisfaction of the objectives of the United States in OCS lease sales.

Subpart C [Reserved]

Subpart D--Joint Bidding


Sec. 260.301  What is the purpose of this subpart?

    The purpose of this subpart is to encourage participation in OCS 
oil and gas lease sales by limiting the requirement for filing 
``Statements of Production'' to certain joint bidders.


Sec. 260.302  What definitions apply to this subpart?

    For the purposes of this subpart, all terms used are defined as in 
Sec. 256.40 of this title.


Sec. 260.303  What are the joint bidding requirements?

    (a) You must file a Statement of Production with the Director, 
according to the requirements of Secs. 256.38 through 256.44 of this 
title if:
    (1) You submit a joint bid for any OCS oil and gas lease during a 
6-month bidding period; and
    (2) You were chargeable for the prior production period with an 
average daily production from all sources in excess of 1.6 million 
barrels of crude oil, natural gas equivalents, and liquefied petroleum 
products.
    (b) The Statement of Production that you file under paragraph (a) 
of this section must state that you are chargeable for the prior 
production period with an average daily production in excess of the 
quantities listed in paragraph (a) of this section.
    (c) If your average daily production in the prior production period 
met or exceeded the quantities specified in paragraph (a) of this 
section, you may not submit a joint bid for any OCS oil and gas lease 
during the applicable 6-month bidding period with any other person 
similarly chargeable. We will disqualify and reject these bids.
    (d) If your average daily production in the prior production period 
met or exceeded the quantities specified in paragraph (a) of this 
section, you may not enter into an agreement prior to a lease sale that 
would result in two or more persons, similarly chargeable, acquiring or 
holding any interest in the tract for which the bid is submitted. We 
will disqualify and reject these bids.

[FR Doc. 01-4490 Filed 2-22-01; 8:45 am]
BILLING CODE 4310-MR-U