11512 Federal Register / Vol. 66, No. 37 / Friday, February 23, 2001 / Rules and Regulations

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.

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 preAct leases to qualify for relief and more

flexibility for companies on both preAct 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 § 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:

• Shortage of rigs capable of drilling

in water depths greater than 1600

meters;

• Lack of infrastructure in water

depths greater than 1600 meters;

• 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

• 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:

• Unusual drilling challenges such as

subsalt targets, extreme well depths, and

drilling encountering high pressure/

high temperature zones;

• Unusual production challenges

such as distance to available

Federal Register / Vol. 66, No. 37 / Friday, February 23, 2001 / Rules and Regulations 11513

infrastructure, high sulphur and low

API gravity crude oils, and areas with a

history of poor reservoir performance;

• The value of increased competition

from greater bidding interest sparked by

royalty relief; and

• 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 §§ 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 §§ 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:

• the expectation that the bigger and

better situated tie-back fields already

have been leased,

• the uncertainty a resource owner

faces about access to another’s facilities,

and

• 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-backsized fields may be developed as standalones 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 tiebacks 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.

11514 Federal Register / Vol. 66, No. 37 / Friday, February 23, 2001 / Rules and Regulations

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

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

11516 Federal Register / Vol. 66, No. 37 / Friday, February 23, 2001 / Rules and Regulations

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:

• Annual revenues of $5 million or

less for exploration service and field

service companies.

• 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 (mid2000) 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 onethird 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 multimillion 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 onethird 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

Federal Register / Vol. 66, No. 37 / Friday, February 23, 2001 / Rules and Regulations 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 × $0.5 approximately = $20

(11⁄3 × 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 § 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 §§ 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.

11518 Federal Register / Vol. 66, No. 37 / Friday, February 23, 2001 / Rules and Regulations

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—rightsof-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 § 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:

§ 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.

For— Issued as a result of a sale held— The lessee must pay rental—

(1) An oil and gas lease .................. Before March 26, 2001 .................. On or before the 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, 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.

(3) A mineral lease for other than

oil or gas.

Before March 26, 2001 .................. On or before the first day of each lease year before the discovery of

paying quantities.

(4) A mineral lease for other than

oil or gas.

After March 26, 2001 ..................... On or before the 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 § 256.40, the introductory

paragraph is revised to read as follows:

§ 256.40 Definitions

The following definitions apply to

§§ 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?

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

§ 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.

§ 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.

§ 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 §§ 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 §§ 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 § 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

§ 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.

§ 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

§ 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

11520 Federal Register / Vol. 66, No. 37 / Friday, February 23, 2001 / Rules and Regulations

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.

§ 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

rate of not less than 12.5 percent.

Cash bonus ........... The highest responsible 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

bonus.

Royalty rate ........... We will specify the fixed amount 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 royalty

rate of not less than 12.5 percent at

the beginning of the lease period.

Cash bonus ........... (1) We will calculate the royalty rate the highest responsible qualified bidder

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 slidingscale 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

the net profits of no less than 30 percent.

Cash bonus ........... (1) If we award you a lease as the highest responsible 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 § 220.022. You will calculate the net profit share base according to § 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 § 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

rate(s) during one or more periods of

production.

Cash bonus ........... (1) We may suspend or defer royalty for a period, volume, 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)

based on formula(s) or schedule(s)

during one or more periods of production.

Cash bonus ........... We will base the royalty rate on formula(s) or schedule(s) specified in the Notice of OCS Lease Sale published in the Federal Register.

(g) Cash bonus with a fixed royalty rate

of not less than 12.5 percent, at the

beginning of the lease period, suspension of royalties for a period, volume,

or value of production, or depending

upon selected characteristics of extraction, and with suspensions that

may vary based on the price of production.

Cash bonus ........... Except for periods of royalty suspension, you will pay a fixed royalty rate of not

less than 12.5 percent. If we award to you a lease under this system, you

must calculate the royalty due during the designated period using the 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.

Federal Register / Vol. 66, No. 37 / Friday, February 23, 2001 / Rules and Regulations 11521

§ 260.111 What conditions apply to the

bidding systems that MMS uses?

(a) For each of the bidding systems in

§ 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 § 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

§ 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 § 260.113. For purposes of

this section and §§ 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.

§ 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 § 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.

§ 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:

Water depth

Minimum

royalty suspension

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

§ 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.

§ 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.

§ 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.

§ 260.117 What other provisions apply to

royalty suspension volumes for eligible

leases?

In addition to the provisions in

§§ 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

11522 Federal Register / Vol. 66, No. 37 / Friday, February 23, 2001 / Rules and Regulations

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

§ 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 §§ 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.

§ 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.

§ 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 § 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 §§ 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.

§ 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.

§ 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

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

§ 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 § 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

§ 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.

§ 260.302 What definitions apply to this

subpart?

For the purposes of this subpart, all

terms used are defined as in § 256.40 of

this title.

§ 260.303 What are the joint bidding

requirements?

(a) You must file a Statement of

Production with the Director, according

to the requirements of §§ 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