Federal Register / Vol. 65, No. 222 / Thursday, November 16, 2000 / Proposed Rules 69259

30A1499, and a total of 484 engines in

the worldwide fleet. The total cost to the

domestic fleet to remove and replace

these disks at the new life limit of 4000

CIS, rather than the former life limit of

5000 CIS, is estimated to be $6,331,015.

Regulatory Impact

This proposed rule does not have

federalism implications, as defined in

Executive Order 13132, because it

would not have a substantial direct

effect on the States, on the relationship

between the national government and

the States, or on the distribution of

power and responsibilities among the

various levels of government.

Accordingly, the FAA has not consulted

with state authorities prior to

publication of this proposed rule.

For the reasons discussed above, I

certify that this proposed regulation (1)

is not a ‘‘significant regulatory action’’

under Executive Order 12866; (2) is not

a ‘‘significant rule’’ under the DOT

Regulatory Policies and Procedures (44

FR 11034, February 26, 1979); and (3) if

promulgated, will not have a significant

economic impact, positive or negative,

on a substantial number of small entities

under the criteria of the Regulatory

Flexibility Act. A copy of the draft

regulatory evaluation prepared for this

action is contained in the Rules Docket.

A copy of it may be obtained by

contacting the Rules Docket at the

location provided under the caption

ADDRESSES.

List of Subjects in 14 CFR Part 39

Air transportation, Aircraft, Aviation

safety, Safety.

The Proposed Amendment

Accordingly, pursuant to the

authority delegated to me by the

Administrator, the Federal Aviation

Administration proposes to amend part

39 of the Federal Aviation Regulations

(14 CFR part 39) as follows:

PART 39—AIRWORTHINESS

DIRECTIVES

1. The authority citation for part 39

continues to read as follows:

Authority: 49 U.S.C. 106(g), 40113, 44701.

§ 39.13 [Amended]

2. Section 39.13 is amended by

adding the following new airworthiness

directive:

Pratt & Whitney Canada: Docket No. 2000–

NE–24–AD.

Applicability: Pratt & Whitney Canada

(P&WC) Model PW305 and PW305A turbofan

engines, with stage 4 low pressure turbine

(LPT) disks, part numbers (P/N’s) 30A1457

and 30A1499. These engines are installed on

but not limited to British Aerospace BAe. 125

1000A, BAe. 125 1000B, Hawker 1000 and

Learjet 60 series airplanes.

Note 1: This airworthiness directive (AD)

applies to each engine identified in the

preceding applicability provision, regardless

of whether it has been modified, altered, or

repaired in the area subject to the

requirements of this AD. For engines that

have been modified, altered, or repaired so

that the performance of the requirements of

this AD is affected, the owner/operator must

request approval for an alternative method of

compliance in accordance with paragraph (c)

of this AD. The request should include an

assessment of the effect of the modification,

alteration, or repair on the unsafe condition

addressed by this AD; and, if the unsafe

condition has not been eliminated, the

request should include specific proposed

actions to address it.

Compliance: Required as indicated, unless

accomplished previously.

To prevent premature LPT disk failure due

to cracking of the LPT disks, which could

result in an uncontained engine failure and

damage to the airplane, accomplish the

following:

New Stage 4 LPT Life Limit

(a) Remove stage 4 LPT disks, P/N’s

30A1457 and 30A1499, prior to exceeding

the new life limit of 4000 cycles-in-service

(CIS).

(b) Except for the provisions of paragraph

(c) of this AD, no parts, identified by P/N in

paragraph (a) of this AD, that exceed the new

life limit of 4000 CIS, may be installed.

Alternative Method of Compliance

(c) An alternative method of compliance or

adjustment of the compliance time that

provides an acceptable level of safety may be

used if approved by the Manager, Engine

Certification Office (ECO). Operators shall

submit their request through an appropriate

FAA Principal Maintenance Inspector, who

may add comments and then send it to the

Manager, ECO.

Note 2: Information concerning the

existence of approved alternative methods of

compliance with this airworthiness directive,

if any, may be obtained from the ECO.

Ferry Flights

(d) Special flight permits may be issued in

accordance with §§ 21.197 and 21.199 of the

Federal Aviation Regulations (14 CFR 21.197

and 21.199) to operate the airplane to a

location where the requirements of this AD

can be accomplished.

Issued in Burlington, MA, on November 9,

2000.

David A. Downey,

Assistant Manager, Engine and Propeller

Directorate, Aircraft Certification Service.

[FR Doc. 00–29379 Filed 11–15–00; 8:45 am]

BILLING CODE 4910–13–U

DEPARTMENT OF THE INTERIOR

Minerals Management Service

30 CFR Part 203

RIN 1010–AC71

Relief or Reduction in Royalty Rates—

Deep Water Royalty Relief for OCS Oil

and Gas Leases Issued After 2000

AGENCY: Minerals Management Service

(MMS), Interior.

ACTION: Proposed rule.

SUMMARY: This proposed rule revises

regulations on royalty relief for oil and

gas producers on the Outer Continental

Shelf (OCS). It provides for suspension

or reduction of royalty on a case-by-case

basis for certain additional categories of

OCS leases. Also, it identifies

circumstances when we may consider

special royalty relief outside our

established end-of-life and deep water

royalty relief (DWRR) programs.

DATES: We will consider all comments

we receive by December 18, 2000. We

will begin reviewing comments then

and may not fully consider comments

we receive after December 18, 2000.

ADDRESSES: If you wish to comment,

you may mail or hand-carry comments

to the Department of the Interior,

Minerals Management Service; Mail

Stop 4024; 381 Elden Street; Herndon,

Virginia 20170–4817; Attention: Rules

Processing Team (RPT). The RPT’s email address is:

rules.comments@MMS.gov.

FOR FURTHER INFORMATION CONTACT:

Marshall Rose, Economics Division, at

(703) 787–1536.

SUPPLEMENTARY INFORMATION: The OCS

Lands Act (43 U.S.C. 1337 et seq.) is the

basis for our regulations on suspending

or lowering royalties on OCS leases.

This rule describes how certain new

deep water leases may qualify for

royalty suspensions and what

circumstances might cause us to grant

royalty relief outside normal

procedures.

Background

The regulations at 30 CFR part 203

implement the Secretary of the Interior’s

(Secretary) authority to grant royalty

relief to OCS leases. Section 302 of the

Outer Continental Shelf Deep Water

Royalty Relief Act of 1995 (Pub. L. 104–

58) (the Act), gave us the authority to

promote development and production of

marginal resources in certain areas by

suspending royalties. Existing

regulations describe our programs in

three discretionary relief situations—

leases nearing the end of their life, new

69260 Federal Register / Vol. 65, No. 222 / Thursday, November 16, 2000 / Proposed Rules

developments in water 200 meters or

deeper (deep water) in the Gulf of

Mexico (GOM), or deep water expansion

projects in the GOM. Our programs

balance the effectiveness of royalty

relief to encourage production that

otherwise would not occur with receipt

of fair market value for public resources

in the specific circumstances of the

individual leases.

Discretionary Relief To Promote Future

Deep Water Development

Promotion of development with

discretionary royalty relief serves

several public purposes. In marginal

circumstances, royalty suspension can

encourage development of resources

that otherwise might be bypassed.

Royalty suspension can also lead to new

production that uses existing

infrastructure. Further, making relief

discretionary avoids the need to offer

blanket relief to whole categories of

leases, many of which do not need it to

attract exploration or development

interest.

The Act contained the following

provisions relating to DWRR:

• It authorized granting royalty relief

both to nonproducing leases and to

expansion projects on producing leases

issued before adoption of royalty

suspension in lease terms (pre-Act

leases).

• It directed that we implement this

authority in deep water (200 meters and

greater water depth) because of the

greater costs and economic risks

involved in operating at those depths

than in shallower water.

• It set out a qualification test

intended to grant relief only when

development otherwise would not make

economic sense.

Based on the Act, our current

regulations governing pre-Act leases

oblige us to consider each field in its

entirety. That approach commits us to

evaluating all the resources that the

field may contain. To improve the

assumptions that we have to make, we

propose to add language to invite

applicants to share information they

may have on other leases that may

eventually become part of the field. (See

clarifications we propose in § 203.63)

Also, we propose to add language to

clarify the reservoir and well data we

are looking for in the geological and

geophysical (G&G) report part of the

application. (See changes proposed to

§ 203.86) Both of these proposed

changes reflect additional information

we have requested from previous

applicants.

After November 2000, we will issue

new deep water leases. Some will be

like pre-Act leases in that we will issue

them with no royalty suspension (RS)

volume. Others, which we call RS

leases, will have a royalty suspension

included in the lease terms. In some

circumstances, the size of the royalty

suspension in the lease may be

inadequate to induce development. For

instance, stand-alone development of a

marginal prospect may require more

relief than a royalty suspension

designed for a tie-back development.

Because may of the special risks

associated with deep water

development remain, we propose to

offer all leases issued in sales after

November 2000 (post-2000 deep water

leases) the opportunity to qualify for

enough royalty suspension to make a

development project or an expansion

project economic. Deep water leases

issued after the date of enactment of the

Act and prior to November 28, 2000

(eligible leases), may not apply for

royalty relief beyond the eligible

amount specified in the lease.

Since the minimum suspension

volumes set in the Act do not apply to

leases issued in sales held after

November 28, 2000, we propose to offer

royalty suspension volumes on a project

rather than a field-basis for post-2000

deep water leases. Specifically, any

future deep water lease that lies west of

87 degrees, 30 minutes west longitude

in the GOM may apply for royalty

suspension on a development project if

it had not produced, or on an expansion

project if it has produced. Hereinafter,

unless otherwise specified, reference to

a ‘‘project’’ includes either a

development of an expansion project.

(See the new applicant category we add

in proposed changes to § 203.60.)

The Act established a deadline by

which we must evaluate a DWRR

application for a pre-Act lease. The

deadline helps development planning

by giving applicants certainty about

how long they can expect to wait for our

relief determination. When companies

have other investment opportunities,

that planning certainty may be an

important factor for keeping a marginal

project alive. We plan to retain this

deadline as a commitment for

applications for post-2000 deep water

leases. The Act also sets a default

royalty suspension in the event we fail

to act in time on an application. We

propose to adopt a default royalty

suspension amount that reflects the

length of the delay, rather than the fixed

default amount set by the DWRR Act for

pre-Act leases. Specifically, if we fail to

render a DWRR determination within

180 days (plus authorized extensions), a

project on a post-2000 deep water lease

will produce royalty-free for the number

of months we delay a decision, plus the

entire volume which our belated

decision grants. (See the proposed new

category we add to the table in

§ 203.66.)

Adjustments to Our DWRR Program

We have considered six DWRR

applications over 4 years under the

existing rules in 30 CFR part 203.

During those evaluations, we identified

some program elements that may

produce results contrary to our

intentions. We will therefore adjust

provisions on minimum suspension

volumes, sunk costs, discount rates,

performance conditions, and allowable

price increases while we modify these

rules to authorize applications for

royalty suspension by leases issued in

OCS sales after November 2000.

Adjustments to Minimum Suspension

Volumes and Relief Shares

Except for an application involving a

pre-Act lease on a field that did not

produce before the Act, we propose to

reduce the minimum suspension

volumes for DWRR we grant to

nonproducing leases. The field-sized

minimums established in the Act will

continue to apply to qualifying

applications that involve pre-Act leases.

Congress based those original

minimums on cost and producibility

estimates from the early 1990’s for field

development. Since then, improved

knowledge of deep water resources,

technical progress, and new

infrastructure have significantly

reduced the size necessary for an

economic prospect. As early as February

1996, the ‘‘Oil and Gas Journal’’

reported that industry experts believe

the economic threshold for developing

deep water projects had dropped from

the 150 million barrels of oil equivalent

(MMBOE) range to the 30 to 35 MMBOE

range because deep water fields were

proving more prolific and less

troublesome than fields on the nearshore shelf. The fact that the Act’s

minimum suspension volumes exceed

the expected resource sizes (in some

cases by a large margin) in all but one

of the deep water field applications we

have reviewed, reflects the change in

economic threshold.

We propose to offer more appropriate

minimum royalty suspension volumes

for development projects and for

expansion projects that qualify for relief.

For a development project on a preproduction RS lease, the minimum will

equal the royalty suspension volume

with which we issued the lease, plus an

increment explained in the following

section on sunk cost. As explained in

our companion proposed rule modifying

30 CFR part 260, published on

Federal Register / Vol. 65, No. 222 / Thursday, November 16, 2000 / Proposed Rules 69261

September 14, 2000 (65 FR 55476), we

plan to update the royalty suspension

volumes with which we issue RS leases

over time as needed. We also propose to

offer a minimum suspension volume to

expansion projects and to development

projects on leases issued with no royalty

suspension volume in sales after

November 2000. The minimum for these

projects will equal the increment

explained in the next section on sunk

cost.

When multiple nonproducing RS

leases participate, the minimum volume

suspension for the project equals the

sum of the royalty suspension volumes

applicable to the participating leases

plus the increment explained in the

next section. As with an expansion

project, the applicant defines the scope

of the development project, and relief

applies only to wells included in the

application. We reserve the right, as we

do under the current program, to

remove nonprospective wells or leases

from the evaluation. (See the proposed

new paragraph and conforming changes

in § 203.69.)

With one exception, all leases

participating in a successful application

for DWRR share the single relief volume

we approve. If the application involves

a pre-Act lease, the single volume must

at least equal the field-sized minimum

set in the Act and applies to all

production from the field. In these

cases, we evaluate field rather than

project economics, and all lessees share

the volume we grant to the field.

If the application involves only post2000 deep water leases, the single relief

volume equals the amount we judge

necessary to make the project economic.

In this case, the royalty suspension

replaces any suspension volume in the

lease instruments and only applies to

the reservoirs identified in the

application. Thus, should a qualifying

project fail to produce the full royalty

suspension volume we grant in response

to an application, the leases that

participated in the application may not

apply the unused volume suspension to

other production. To do otherwise

encourages understatement of a lease’s

potential in the application we review.

If no production has occurred from the

participating leases, the royalty

suspension volume is subject to the

minimum applicable for the

development or expansion project.

The one exception to sharing a single

volume occurs when an eligible lease is

part of the field, In that instance, the

eligible lease may produce royalty-free

up to its field-sized suspension volume,

regardless of the volume we set for the

project proposed by the other leases.

However, production from a

development project on the same field

counts against the field-sized volume

available to the eligible lease.

We reflect these principles by adding

the new applicant category in the

proposed changes to § 203.71.

Adjustments to the Evaluation Elements

Except for cases that involve fields

with a pre-Act lease, we propose to

change the way we count sunk costs in

the determination of whether an

application qualifies for royalty relief.

To comply with the Act’s instruction to

consider historic costs for pre-Act

leases, we originally included the costs

of and after the discovery well when

calculating whether a field appeared

economic, but only on fields where no

production had yet occurred. We now

propose to allow the documented costs

of the discovery well, both for

development projects on post-2000 deep

water leases and for expansion projects

on pre-Act or on post-2000 deep water

leases. The discovery well is the one

that penetrates the first reservoir

targeted by the project and that meets

the well producibility requirements of

30 CFR part 250. We expect that

allowing sunk costs for this broader

scope of prospects will help promote

exploration in deep water and greater

use of the opportunity to obtain

supplementary royalty suspension

volumes. Allowing some sunk costs to

more applicants permits more leases to

quality for royalty relief and thus

encourages more exploration.

Unlike the treatment of sunk costs on

pre-Act leases, we do not intend to

count pre-application costs subsequent

to the discovery well. This more limited

treatment reflects a balanced approach

to competing considerations. On the one

hand, overcoming the unusual risks of

deep water development may depend

on Government sharing some of the

uncertainty burden, even on expansion

projects. Also, our regulations require

only a discovery well before we will

consider an application. Further, the

uneconomic level for development

projects will be lower because

determination of whether the project

qualifies for a supplemental volume

suspension includes the value of any

volume suspension with which we

issued the participating leases. On the

other hand, only future costs, not

historic costs, influence decisions on

whether to proceed on a specific project.

Further, activities and costs other than

the discovery well, such as acquiring

seismic data, completing engineering

studies, or drilling additional wells, are

conducted at the applicant’s discretion

before filing an application for royalty

relief. Additionally, costs associated

with these other activities are more

likely than a discovery well to benefit

other prospects for help attract other

partners or successor owners to this

prospect. Counting only the cost of the

discovery well balances sharing the

exploration risk with the responsibility

to include only relevant costs. (See the

new category of sunk cost treatment

proposed in the table in § 203.68.)

We do not propose to change the

exclusion of sunk cost from the

determination of how much relief a

project needs to become economic

(volume test). To do otherwise risks

adding relief well beyond that necessary

to make development economic. Also, it

directs more relief to just the wrong

projects, specifically those that are more

likely to continue anyway because they

have relatively smaller costs left to incur

and that must be covered by future

production. However, we will ensure

that inclusion of sunk cost in the

qualification determination gives the

applicant an unambiguous benefit. We

propose to do that by adding an

increment of royalty-free production to

any royalty suspension volume with

which a qualifying project starts the

application process. Our qualification

test does factor in the volume

suspensions with which we issued

leases participating in the application,

but not this increment.

We propose to set this increment at 10

percent of the most likely resource size

we agree is appropriate for the project.

For instance, consider a development

project that MMS agrees has a most

likely resource size of 60 MMBOE. If it

qualifies for relief and is located on RS

leases that we issued with a combined

royalty suspension volume of 20

MMBOE, it will get a royalty suspension

of at least 26 MMBOE. An expansion

project in this situation would get at

least 6 MMBOE.

This form of increment improves on

a universal fixed increment or one tied

to water depth because it is projectspecific. Further, its relatively small size

ensures that it neither provides too

much or too little relief to encourage

individual project development and

program-wide exploration. It is

preferable to a time-based increment,

such as an extra year of royalty-free

production, because it does not risk

damaging ultimate recovery by creating

an incentive to accelerate production to

avoid royalties. A sub-marginal project

may need royalty suspension for

anywhere from a small fraction of its

reserves to virtually all of them to be

worth developing. If something less

than royalty-free production of 50

percent of reserves on average justifies

development on a look-forward basis

69262 Federal Register / Vol. 65, No. 222 / Thursday, November 16, 2000 / Proposed Rules

(excluding sunk costs), a fraction of that

could be safely provided to induce

exploration. The 10-percent share

represents a considered amount

designed to encourage exploration on

future projects deemed marginally or

sub-marginally profitable. This policy

leaves up to 90 percent of the project’s

production still subject to royalties.

Thus, the project-specific increment

serves as a uniform replacement for

sunk cost in the volume determination

test. This increment assures any project

that qualifies for supplemental relief

because of sunk cost will have an

additional volume suspension on top of

what it has already. A development or

an expansion project, therefore, may get

a somewhat larger volume suspension

than it needs to be economic on a lookforward basis. Alternatively, the project

would get a larger volume than the

minimum volume suspension if our

evaluation indicates it needs more relief

than the minimum to be economic on a

look-forward basis. (See changes in

§ 203.69.)

To help us evaluate the effects of

revising our treatment of sunk cost, we

would like your comments on the

following questions.

• How does a credit for sunk costs

change your incentive to explore a risky

prospect and to apply for royalty relief?

• What other treatments of sunk costs

promote exploration without resulting

in excessive volume suspension for

many projects?

Also, we propose to lower the

viability standard we set as a

prerequisite to evaluating a field’s or a

project’s need for relief. Our current

evaluation procedure requires that the

application meet two economic criteria.

First, the application must show that a

field or project is viable, i.e., would be

economic assuming it paid no royalties

and no sunk costs. Second, qualification

for relief requires that the application

show a nonproducing field would not

be profitable assuming it paid certain

sunk costs and full royalties, or that an

expansion project would not be

profitable paying full royalties. We have

revised § 203.67 to clarify the dual

criteria for qualification.

Until now, we insisted that the same

discount rate be used for both the

viability and the profitability estimates.

While ensuring that the application

does not give an overly pessimistic

portrayal of the field or expansion

project, this equivalence of discount

rates may be too restrictive.

Development without royalty or sunk

costs should be less risky than if these

costs have to be covered. Thus, the cost

of capital under the viability

circumstances should be lower than

when full royalties and sunk costs must

be paid. To acknowledge this potential

difference, we propose to accept

applications that demonstrate fields or

projects have a positive value at a 10-

percent real rate of discount. Applicants

retain the right to set the discount rate

we use for the profitability test at any

value between 10 and 15 percent. (See

changes to the guidelines that

accompany § 203.67.) The MMS

website, www.gomr.mms.gov/homepg/

offshore/royrelef.html, provides the

most current version of these guidelines,

including the parameters we prescribe

for discount rates and prices.

This change in our discount rate

procedure offsets one effect of changing

the way we treat sunk costs, for leases

other than pre-Act leases, in our

qualification determination. A 10-

percent discount rate has the effect of

raising the estimated present value of

the field or project in the absence of

royalties. Past applicants always chose a

15-percent discount rate. We anticipate

that future applicants will continue to

choose the maximum allowed discount

rate for the full royalty profitability

analysis. Thus, while limiting sunk

costs generally reduces the difference

between the viability and profitability

estimate, a lower discount rate for the

viability estimate than for the

profitability estimate will increase this

difference. The larger difference allows

a wider range of circumstances to

qualify as marginal fields or projects in

need of royalty relief. More generally,

limiting sunk costs for post-2000 deep

water leases and acknowledging that

development risks may be different with

and without royalties makes our

evaluation of economic need more

realistic.

Finally, we are proposing to add

language that clarifies what we seek in

the administrative and design parts of

an application. As with the G&G report,

these changes reflect additional

information we have requested from

previous applicants. (See changes

proposed to §§ 203.83 and 203.87.)

Adjustments to Post-Evaluation

Elements

We propose adjustments in several of

the conditions successful applicants

must meet to realize a royalty

suspension or to re-apply for relief. We

propose adjustments in the deadline to

start fabrication of the development

system, in correcting for overestimating

costs in the application, and in what

constitutes an appropriate reason for us

to reconsider the need for relief. These

three proposed adjustments apply to all

fields or projects seeking a volume

suspension after the effective date of

these revisions. Also, we propose to

specify in the leasing documents the

price thresholds (which we identify at

the time of lease sale) above which we

will suspend any remaining royalty

relief for post-2000 deep water leases.

Current regulations require applicants

to give evidence of a timely

commitment to development by starting

fabrication of their production facility

within 1 year after we approve their

application. We established this

deadline to avoid premature

applications. Requiring that projects or

developments be ready to commence

soon after approval means we make the

relief decision close to the same point

and with about the same quality of

information as the applicant uses to

make the commitment decision. While

the fact that the ability to get into

production quicker than expected

partially accounts for the improvement

in deep water economics, the 1-year-tofabrication deadline we set needs

lengthening. Shortages of drilling,

design, and fabrication capacity for deep

water development may make meeting

the currently required schedule

difficult. Also, we don’t want to

encourage token actions that don’t really

signal the start of development. Thus,

we propose to lengthen the period when

fabrication must start to 18 months after

relief approval. Added to the 6-month

period we use for evaluation, that gives

a full 2 year lead-time between

application and commitment to

development. With our authority to

extend that period for up to 6 months

for events beyond the applicant’s

control, we feel this change should

provide ample time to make the

necessary arrangements to start

development on projects or fields that

receive royalty relief. (See change to

deadlines proposed in § 203.70.)

Along with this deadline change, we

propose to clarify that the meaning of

‘‘starting fabrication’’ requires

continuous fabrication. Starting and

then suspending fabrication of the

production facility does not fulfill this

performance condition. (See the

addition we propose in § 203.76(b)).

Another performance condition we

use to help ensure we deal with a

realistic application has to do with

estimated costs. We require actual

expenditures to equal at least 80 percent

of the costs that the applicant estimates

spending. Both estimated and actual

figures cover the period between the

application and first production. The

current correction for overestimating

actual costs by too much is retention of

only half of the volume suspension we

originally granted. This correction has

no real effect when the minimum

Federal Register / Vol. 65, No. 222 / Thursday, November 16, 2000 / Proposed Rules 69263

suspension volume prescribed by the

Act more than doubles the field’s

expected production. Thus, we propose

to adjust the correction volume to

retention of the smaller of one-half of

the granted suspension volume or onehalf of the most likely production

specified in the application. (See

changes to a deadline and the relief

correction amount proposed in

§ 203.76.)

In conjunction with this change, we

also propose to broaden what

constitutes a development system. For

instance, we will no longer consider

Spars and mini-tension-leg platforms

different development systems. Both are

essentially floaters with export

pipelines and little if any storage

capacity. With this change, we intend to

maximize the flexibility applicants have

to entertain bids for competing versions

of the same basic development system.

We also propose to expand the

situations in which fields or projects

may seek a redetermination of our

initial relief decision. We provide more

flexibility for allowing redeterminations

when relief is withdrawn or

relinquished. Also, we add another

condition in which we permit a

redetermination if we deny your

application or you seek to increase an

approved volume suspension. In these

instances, in addition to substantial

increases in estimated costs, reductions

in expected prices, or new geologic

information on the field, we propose to

allow a re-application for a change of

development system under certain

conditions. It must be clear that the

original application did not consider or

deem the new development system

infeasible. This situation might arise

because new technology becomes

available or a new owner with a

different perspective takes over field

development after the initial

application. In either case, the new

application needs to demonstrate that

the new approach more efficiently

develops the resource than what we

originally evaluated. By more efficient,

we mean either clearly lower costs or

clearly larger recovery, so that estimated

profit would increase under the

circumstances we previously evaluated.

(See the new fourth condition and the

removal of the restriction on the price

condition in the changes we propose to

§ 203.74.)

More realistic performance conditions

may add value to the successful

applicant’s explicit right to renounce

relief. Several successful past applicants

have lost relief because they violated a

withdrawal condition. Rather than wait

until we formally withdraw relief, they

could have renounced relief as soon as

they realized they needed to change the

proposed development system or

significantly revise cost estimates. By

renouncing, they could accelerate the

start of a redetermination, thereby

converting after-tax, sunk costs on

authorized fields to before-tax, postapplication costs for purposes of the

next application. We propose to

simplify § 203.77 to avoid confusion

about this right.

Further, we propose to review the

level we set and to which prices must

rise before the need for royalty relief,

granted under an earlier expectation of

lower prices, disappears. By 1999, the

Act’s escalation procedure meant that

oil prices must exceed $30/bbl or

natural gas prices must exceed $3.80/

MMBtu for an entire calendar year

before pre-Act leases with a remaining

volume suspension owe royalty. For

comparison, royalties reduce realized

price by slightly less than the royalty

percentage, e.g., 12.5 percent for deep

water tracts in greater than 400 meters

(m) of water. When market prices rise

above levels that prompted

development by more than that

percentage for at least a year, the need

for the royalty suspension incentive

disappears, at least for these projects or

fields. Therefore, we propose to suspend

royalty relief for projects when prices

rise and remain substantially above

levels prevalent when we approved

relief. To reflect evolving market

conditions, we will set these threshold

levels in the Notice of Sale and lease

documents associated with each future

lease. (See the proposed changes that

add the new relief recipient category to

§ 203.78.)

Finally, we propose to make clear in

the regulations that we want a Certified

Public Account (CPA) not affiliated with

the applicant to vouch for the historic

data in the application and postproduction report. Thus, we have added

the word ‘‘independent’’ before CPA in

changes proposed to §§ 203.81 and

203.91.

The following table summarizes the

elements of the current DWRR program

that we propose to modify with this

rule.

PROPOSED MODIFICATIONS TO DWRR APPLICATIONS

Element

Current and continuing

program

Applies to pre-Act leases

Proposed changes

Applies to post-2000 deep water leases

Eligibility (Central, Western, and western part

of Eastern Gulf of Mexico).

Leases in 200m or more water depth issued

before 1996.

Leases in 200m or more water depth issued

after 2000.

Royalty-free production can come from ............ Any production from the field until cumulative

recovery volume equals the suspension volume.

Only production from resources identified in

the application until cumulative recovery

equals the suspension volume

Minimum suspension volume for non-producing

leases.

For fields that did not produce before the Act,

matches eligible lease suspension volumes

(17.5, 52.5, 87.5 MMBOE) in equivalent

water depths.

For development projects, matches volumes

designated in sale and lease documents for

various water depths of 200m or greater

plus 10 percent of reserves.

Credit for sunk costs in application ................... For fields with pre-Act leases that did not

produce before the application, after-tax

costs of and after discovery well used in

qualification.

For development projects, after-tax cost of

only the discovery well, except when the

application involves a pre-Act lease.

Threshold oil and gas price levels for lifting relief.Statute sets threshold price for light sweet

crude oil and natural gas.

Lease terms set threshold price for light sweet

crude oil and natural gas.

69264 Federal Register / Vol. 65, No. 222 / Thursday, November 16, 2000 / Proposed Rules

PROPOSED MODIFICATIONS TO DWRR APPLICATIONS

Element

Current and discontinuing

program

Applies to pre-Act leases

Proposed changes

Applies to pre-Act and post-2000 deep water

leases

Discount rate used in evaluation ....................... Same rate used on viability and profitability

tests, applicant chooses between 10% and

15%.

Use 10% on viability test, applicant chooses

rate between 10% and 15% for profitability

test.

Redetermination of field qualification or volume

by MMS.

Available for new well or seismic data, 25%

lower prices, or 20% higher cost.

Available anytime after relief relinquished or

withdrawn. Otherwise, for new well or seismic data, 25% lower prices, 20% higher

cost, or more efficient development system.

Deadline for starting fabrication ......................... Within 1 year of approval, extendable for up

to 1 year.

Within 18 months of approval, extendable for

up to 6 months.

Correction for overestimating cost by 20% or

more.

Retain only half of suspension volume granted Retain only half or smaller of granted suspension volume or most likely resource size.

Minimum suspension volume for expansion

project.

None ................................................................. 10 percent reserves.

Credit for sunk costs in application for expansion project.None ................................................................. After-tax cost of the discovery well.

Royalty Relief in Special Circumstances

Certain circumstances can make

leases ineligible for one of our

established royalty relief programs. Yet,

royalty relief may benefit both the lessee

and the Federal Government. For

example, a recent, significant renovation

of operations prevents a lessee from

seeking end-of-life royalty relief, at least

temporarily. Or, the operator of a

marginal expansion project in less than

200m of water cannot apply for a royalty

suspension, even if it is located in the

central and western GOM. When

combined with other circumstances,

such as a sudden drop in prices or

unusually high original royalty rates,

this ineligibility could cause substantial

resources to be left unproduced. Some

form of royalty relief in these unusual

situations can serve the statutory

purpose of increasing production or

promoting development outside our

established programs. Because of the

rarity of situations that meet these

unusual conditions, we will not

establish another formal royalty relief

program. But, we leave open the

opportunity for an operator to request

relief in special circumstances. Before

evaluating a special relief application,

we require that applicants establish

eligibility. An applicant does this by

gaining our approval that their situation

meets several of the tests listed in the

new § 203.80. Once that is done, we will

establish case-by-case qualification

conditions and relief format appropriate

to the special circumstances.

Can you suggest forms of royalty

reduction that we are not now using that

might encourage increased production

in the special circumstances we propose

in § 203.80?

Procedural Matters

Public Comment Procedure

Our practice is to make comments,

including names and home addresses of

respondents, available for public review

during regular business hours.

Individual respondents may request that

we withhold their home address from

the record, which we will honor to the

extent allowable by law. There may be

circumstances in which we would

withhold from the record a respondent’s

identity, as allowable by law. If you

wish us to withhold your name and/or

address, you must state this

prominently at the beginning of your

comment. We will not consider any

anonymous comments. We will make all

submissions from organizations or

businesses, and from individuals

identifying themselves as

representatives or officials of

organizations or businesses, available

for public inspection in their entirety.

Regulatory Planning and Review

(Executive Order 12866)

The proposed rule is a significant

regulatory action under Executive Order

12866, and is subject to review by the

Office of Management and Budget

(OMB).

a. This proposed rule will not have an

annual economic effect of $100 million

or adversely affect an economic sector,

productivity, jobs, the environment, or

other units of government. This action

describes how certain new deep water

leases may quality for royalty

suspensions and the circumstances

under which we might grant royalty

relief. Historically, we have received

only a limited number of applications

for royalty relief. Based upon our

experience, only a small number of

leases will quality for royalty relief in

any one year, and the annual value of

the relief will be less than $100 million.

The only field that has gone into

production after approval may,

depending on prices, avoid slightly over

$7 million in royalty payments in is first

year of production. The royalty

suspension options in this proposal will

encourage new production from a few

marginal leases. Because royalty

suspension volumes are an incentive to

production, they likely will have a

beneficial effect on the offshore oil

industry, domestic oil and gas supplies,

and jobs. In fact, this program should

increase aggregate OCS production by

making production from marginal fields

more economically feasible.

b. This proposed rule does not create

inconsistencies with other agencies’

actions because it preserves the

concepts and requirements from the

existing rule.

c. This proposed rule is an

administrative change that will not

affect entitlements, grants, user fees,

loan programs, or their recipients. This

proposed rule has no effect on these

programs or rights of the programs’

recipients.

d. This proposed rule does not raise

any novel legal issues, but does raise

policy issues. The proposed rule

extends and supplements the existing

DWRR rule. It describes conditions

under which lessees have the

opportunity to apply for and acquire

royalty relief on post-2000 deep water

leases. Also, it modifies some

conditions under which lessees of preAct leases obtain royalty relief. In

addition, the proposed action describes

special circumstances under which

lessees may apply for royalty relief that

were not specified in our previous

regulations. All of these changes are

consistent with the basic philosophy in

Federal Register / Vol. 65, No. 222 / Thursday, November 16, 2000 / Proposed Rules 69265

the current rule of granting relief only

when applicants show it is

economically necessary for

development.

Regulatory Flexibility (RF) Act

The Department certifies that this

document will 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 proposed rule will not have a

significant adverse economic effect on

offshore lessees and operators,

including those that are classified as

small businesses. The proposed rule

extends the benefit of discretionary

royalty relief to certain OCS leases

issued after November 2000 that qualify

as marginally uneconomic. In any one

year, we are likely to receive only a

small number of royalty relief

applications, which limits the number

of entities the proposed rule may affect.

Based on past experience, we expect to

receive between one and two

applications a year for DWRR. Also,

because firms initiate applications, they

have the ability to avoid any adverse

effects they foresee. As suggested below,

the new provisions proposed should

actually lower the cost to those who

choose to take advantage of the benefit

offered by this regulation. An RF

analysis is not required. A Small Entity

Compliance Guide is not required.

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 Standard Industrial

Classification code 1381, Drilling Oil

and Gas Wells, MMS estimates that a

total of 1,380 firms drill oil and gas

wells onshore and offshore. Of these,

approximately 130 companies are

offshore lessess/operators, based on

current estimates. Publicly available

data indicate that 39 companies qualify

as large firms according to SBA criteria,

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. Of the 211 deep water leases

that have a discovery or production by

mid-2000, 19 large firms are the lessee/

operator of 193, while 7 small firms are

lessee/operator of the other 18. While

that ratio suggests a 1-in-12 chance that

a small operator may apply for relief, 2

of the 16 past applications we received

have been from small operators. This

rule proposes continuing the same basic

application system we now use. Small

operators do not appear to be at a

disadvantage in our application process.

Provisions of the proposed rule, in

comparison with existing rules for

discretionary DWRR for pre-Act leases,

may reduce applicant costs in three

areas:

• First, new applications for DWRR

will be on the basis of a fully identified

project rather than a whole, often

incompletely identified field.

Consequently, applicants may need to

provide less extensive G&G data. For

instance, we will not require them to

submit data they have access to on

reservoirs that may be in the field but

clearly are not part of the project. There

is no sound basis for estimating the size

of any savings associated with this

reduced data burden because only some

applications would involve potential

extra reservoirs. For those that do,

however, this change can reduce the

amount of follow-up data we typically

have to request from applicants and can

expedite our evaluation.

• Second, applicants may no longer

have to incur the cost of additional

drilling or acquisition of new seismic

data to request a determination. While

significant new geologic information or

price or cost changes still enable a

redetermination, applicants may now

seek a redetermination upon

identification of a more efficient

development system. That new reason

could save drilling a new deep water

well at a cost of $20 million or more or

acquiring additional seismic data at a

cost of about $100,000 per tract. We

have received no redetermination

requests. We attribute this to the fact

that the DWRR program has not been

active long enough to reach the

redetermination stage for most of the

applications we have already processed.

• Third, under the proposed rule, we

give successful applicants more time to

initiate development than under

existing rules. This added time gives

operators more time to arrange financing

and to negotiate contracts with

suppliers. Again, there is no sound basis

for estimating the size of any savings

associated with this greater applicant

flexibility. It is clear, however, that this

change, like the other two, cannot be

considered to impose a significant

adverse economic effect on a substantial

number of small business entities. If

anything, all four changes ameliorate

the existing applicant cost burden.

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 proposed rule is not a major rule

under 5 U.S.C. 804(2), the SBREFA.

This proposed rule:

a. Does not have an annual effect on

the economy of $100 million or more.

This proposed rule modifies some

procedures used under the current rule,

specifies how certain new deep water

leases may qualify for royalty

suspensions in the future, and describes

circumstances that may cause us to

grant royalty relief that were not

covered in the current regulations. In

general, the effect of qualifying for a

royalty suspension increases production

from a few marginal fields but does not

change royalty collections—since

without relief, no production or royalty

payments would occur or be expected,

so suspending them forfeits little if any

revenue. To the extent that royalty relief

encourages new production, it benefits

applicants, one-third of which in the

past have been small business. But only

one of the four fields for which we have

approved relief has gone into

production. We expect, however, that in

any one year, this proposed 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 natural gas prices are more

localized, they correlate to oil prices.

The proposed 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.

69266 Federal Register / Vol. 65, No. 222 / Thursday, November 16, 2000 / Proposed Rules

Leasing on the United States OCS is

limited to residents of the United States

or companies incorporated in the

United States. This proposed 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 proposed 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 proposed rule

modifies some procedures in the

existing regulation, describes how

certain new leases may qualify for

royalty suspensions, and specifies

special circumstances that might cause

us to grant royalty relief that were not

considered previously. None of these

changes involve State, local, or tribal

mandates. 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 proposed rule does not have

significant Takings implications. A

Takings Implication Assessment is not

required because the proposed rule

would not take away or restrict a

bidder’s right to acquire or develop 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 from

lessees in the deep water GOM, all of

which is outside State jurisdiction.

States have no role in this activity with

or without this rule. This does not

impose costs on States or localities.

States and local governments play no

part in the administration of the DWRR

program.

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

The information collection

requirements in the proposed

rulemaking remain unchanged from

those currently approved by OMB, and

a new 83–I submission is not required.

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. In

1998, OMB approved the information

collection requirements in the current

regulations under OMB control number

1010–0071.

Based on experience to date, MMS

subsequently determined that the

application filing fee schedule should

be revised. In addition, the need became

apparent for establishing a new fee to

cover applications for ‘‘special relief for

marginal producing leases.’’

Consequently, we initiated the process

to obtain OMB approval of these

changes to the information collection

burden. We published the required 60-

day Federal Register notice on May 11,

2000 (65 FR 30431). The comment

period closed on July 11, 2000; we

received no comments. We then

submitted a request to OMB, and OMB

approved the revised information

collection burden with a current

expiration date of September 30, 2003.

The approved information collection

burden is consistent with the proposed

amendments to the regulations.

As part of our continuing effort to

reduce paperwork and respondent

burdens, we invite your comments on

any aspect of the reporting burden in

part 203. MMS will address comments

on the information collection burden in

the final rule preamble. Refer to the

ADDRESSES section for mailing

instructions. We specifically solicit

comments on the following questions:

(a) Is the proposed collection of

information necessary for MMS to

properly perform its functions, and will

it be useful?

(b) Are the estimates of the burden

hours of the proposed collection

reasonable?

(c) Do you have any suggestions that

would enhance the quality, clarity, or

usefulness of the information to be

collected?

(d) Is there a way to minimize the

information collection burden on those

who are to respond, including the use

of appropriate automated electronic,

mechanical, or other forms of

information technology?

The title of the collection of

information is ‘‘30 CFR Part 203, Relief

or Reduction in Royalty Rates.’’

Respondents include approximately 130

Federal OCS oil and gas lessees. The

frequency of response is on occasion.

Responses to this collection of

information are required to obtain or

retain a benefit. MMS will protect

proprietary information under

applicable law and 30 CFR 203.63(b)

and 250.196.

The following chart provides our

estimated ‘‘hour’’ burden for part 203

regulations and the application and

audit fee ‘‘non-hour’’ cost burdens

authorized under § 203.3

Reporting or recordkeeping requirement 30 CFR Part 203

Application/audit fees

Annual responses Hours per

response

Annual burden

hours

OCS Lands Act Reporting

Application—leases that generate earnings that can’t sustain continued

production (end-of-life lease).

2 Applications .................................. 100 200

Application 2×$12,000=$24,000 1

Audit 1×$10,000=$10,000

Application—special relief for marginal producing lease (expect less

than 1 per year—new category).

1 Application .................................... 250 250

Application 1×$15,000=$15,000 1

Audit 1×$10,000=$10,000

Federal Register / Vol. 65, No. 222 / Thursday, November 16, 2000 / Proposed Rules 69267

Reporting or recordkeeping requirement 30 CFR Part 203

Application/audit fees

Annual responses Hours per

response

Annual burden

hours

§ 203.55 Renounce relief arrangement (seldom, if ever will be used;

minimal burden to prepare letter).

1 Letter ............................................ 1 1

§ 203.81, 203.83 through 203.89 required reports .................................... Burden included with applications.

OCS Lands Act Reporting Subtotal ................................................... 4 responses ..................................... N/A 451

Processing Fees=$59,000

DWRAA Reporting

Application—leases in designated areas of GOM deep water acquired in

lease sale before 11/28/95 or after 11/28/00 and are producing (deep

water expansion project).

1 Application .................................... 2,000 2,000

Application 1×$39,000=$39,000

Audit

Application—leases in designated areas of deep water GOM, acquired

in lease sale before 11/28/95 or after 11/28/00, that have not produced (pre-Act or post-2000 deep water leases).

1 Application .................................... 2,000 2,000

Application 1×$49,000=$49,000

Audit 1×$25,000=$25,000

Application—short form to add or assign pre-Act lease ........................... 1 Application .................................... 40 40

Application 1×$1,000=$1,000

No Audit

Application—preview assessment (seldom if ever will be used as applicants opt for binding determination by MMS instead).1 Application .................................... 900 900

Application 1×$46,600=$46,600

No Audit

Application—special relief for marginal expansion project or marginal

non-producing lease (expect less than 1 per year—new category).

1 Application .................................... 1,000 1,000

Application 1×$49,000=$49,000

Audit 1×$20,000=$20,000

Redetermination ......................................................................................... 1 Redetermination ........................... 500 500

Application 1×$32,000=$32,000 1

Audit 1×$25,000=$25,000

§ 203.70, 203.81, 203.90, 203.91 Submit fabricator’s confirmation report 2 Reports ......................................... 20 40

§ 203.70, 203.81, 203.90, 203.92 Submit post-production development

report.

2 Reports 1 ....................................... 50 100

§ 203.77 Renounce relief arrangement (seldom, if ever will be used;

minimal burden to prepare letter).

1 Letter ............................................ 1 1

§ 203.79(a) Request reconsideration of MMS field designation ............... 4 Requests ...................................... 400 1,600

§ 203.79(c) Request extension of deadline to start construction .............. 1 Request ........................................ 2 2

§ 203.81, 203.83 through 230.89 Required reports. ................................. Burden included with applications 0

DWRR Act Reporting Subtotal ........................................................... 16 Responses ................................. N/A 8,183

Processing Fees=$286,600

RecordKeeping Burden

§ 203.91 Retain supporting cost records for post-production development/fabrication reports (records retained as usual/customary business practice; minimal burden to make available at MMS request).2 Record keepers ............................ 8 16

Total Annual Burden ........................................................................... 22 Responses ................................. N/A 8,650

69268 Federal Register / Vol. 65, No. 222 / Thursday, November 16, 2000 / Proposed Rules

Reporting or recordkeeping requirement 30 CFR Part 203

Application/audit fees

Annual responses Hours per

response

Annual burden

hours

Total Processing Fees=$345,600

1 In addition, under § 203,81, a report prepared by an independent CPA must accompany the application and post-production report (except

expansion project, short form, and preview assessment applications are excluded). The OCS Lands Act applications will require this report only

once; the DWRR Act applications will require this report at two stages—with the application and post-production development report for successful applicants. We estimate an average cost for a report is $45,000 and that seven CPA certifications per year will be necessary if the applications are approved. The total estimated annual ‘‘non-hour’’ cost burden for this requirement is $315,000 ($45,000 per certification × 7 CPA

certifications=$315,000).

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.

Clarity of this Regulation

Executive Order 12866 requires each

agency to write regulations that are easy

to understand. We invite your

comments about how to make this

proposed rule easier to understand,

including answers to questions like the

following:

(1) Are the criteria for obtaining

royalty relief clearly specified?

(2) Are the procedures for obtaining

royalty relief clearly described?

(3) Are the rules for determining

royalty suspension volumes for the

various categories of leases clearly

stated?

(4) Are the conditions for obtaining

royalty relief in special circumstances

adequately specified?

(5) Does the proposed rule contain

technical language or jargon that

interferes with its clarity?

(6) Does the format of the proposed

rule (grouping and ordering of sections,

use of headings, etc.) increase or reduce

its clarity?

(7) Would the proposed rule be easier

to understand if it were divided into

more, but shorter, sections?

(8) Is there anything else we can do

to make the proposed rule easier to

understand? Send a copy of any

comments that concern how we could

make this proposed rule easier to

understand to: Office of Regulatory

Affairs, Department of the Interior,

Room 7229, 1849 C Street, N.W.,

Washington, D.C. 20240. You may also

e-mail your comments to:

Exsec@ios.doi.gov.

List of Subjects in 30 CFR Part 203

Continental shelf, Government

contracts, Indians-lands, Minerals

royalties, Oil and gas exploration,

Public lands-mineral resources,

Reporting and recordkeeping

requirements, Sulphur.

Dated: October 30, 2000.

Sylvia V. Baca,

Assistant Secretary, Land and Minerals

Management.

For the reasons stated in the

preamble, the Minerals Management

Service (MMS) proposes to amend 30

CFR part 203 as follows:

PART 203—RELIEF OR REDUCTION IN

ROYALTY RATES

1. The authority citation for part 203

continues to read as follows:

Authority: 25 U.S.C. 396 et seq.; 25 U.S.C.

396a et seq.; 25 U.S.C. 2101 et seq.; 30 U.S.C.

181 et seq.; 30 U.S.C. 351 et seq.; 30 U.S.C.

1001 et seq.; 30 U.S.C. 1701 et seq.; 31 U.S.C.

9701 et seq.; 43 U.S.C. 1301 et seq.; 43 U.S.C.

1331 et seq.; and 43 U.S.C. 1801 et seq.;

2. Section 203.0 is amended by

adding ‘‘Development project’’ and

‘‘Royalty suspension (RS) lease’’ and

revising ‘‘Authorized field,’’ ‘‘Eligible

lease,’’ ‘‘Expansion project,’’

‘‘Fabrication (or start of construction),’’

‘‘New production,’’ ‘‘Pre-Act lease,’’

‘‘Redetermination,’’ and ‘‘Sunk costs’’ to

read as follows:

§ 203.0 What definitions apply to this part?

Authorized field means a field:

(1) Located in a water depth of at least

200 meters and in the Gulf of Mexico

west of 87 degrees, 30 minutes West

longitude;

(2) That includes one or more pre-Act

leases; and

(3) From which no current pre-Act

lease produced, other than test

production, before November 28, 1995;

* * * * *

Development project means a project

that:

(1) You propose in a Development

Operations Coordination Document

(DOCD); and

(2) Is located on one or more

contiguous leases that;

(i) Were issued in a sale held after

November 28, 2000;

(ii) Are located in the Gulf of Mexico

west of 87 degrees, 30 minutes West

longitude; and

(iii) Have had no production (other

than test production) before the current

application for royalty relief.

* * * * *

Eligible lease means a lease that:

(1) Results from a 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.

Expansion project means a project

you propose in a Development

Operations Coordination Document

(DOCD) or a Supplement approved by

the Secretary of the Interior after

November 28, 1995, that will

significantly increase the ultimate

recovery of resources from pre-Act lease

or a lease issued in a sale held after

November 28, 2000. For a pre-Act lease,

it must also involve a substantial capital

investment (e.g., fixed-leg platform,

subsea template and manifold, tensionleg platform, multiple well project, etc.).

Fabrication (or start of construction)

means evidence of irreversible

commitment to a concept and scale of

development, including copies of a

binding contract between you (as

applicant) and a fabrication yard, a

letter from a fabricator certifying that

continuous construction has begun, and

a receipt for the customary down

payment.

* * * * *

New production means any

production from a current pre-Act lease

from which no royalties are due on

production, other than test production,

before November 28, 1995. Also, it

means any production resulting from

lease-development activities on a

Federal Register / Vol. 65, No. 222 / Thursday, November 16, 2000 / Proposed Rules 69269

current pre-Act lease or a lease issued

in a sale after November 28, 2000, under

a Development Operations Coordination

Document (DOCD) or a Supplement

approved by the Secretary of the Interior

after November, 28, 1995, that

significantly expands production.

* * * * *

Pre-Act lease means a lease that:

(1) Results from a 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 this part.)

* * * * *

Redetermination means your request

for us to reconsider our determination

on royalty relief because:

(1) We have rejected your application;

(2) We have granted relief but you

want a larger suspension volume;

(3) We withdraw approval; or

(4) You renounce royalty relief.

* * * * *

Royalty suspension (RS) lease means

a lease that:

(1) Results from a lease sale held after

November 28, 2000;

(2) Is in a location or planning area

specified in the Notice of Sale offering

that lease; and

(3) Is offered subject to a royalty

suspension volume.

Sunk costs on an authorized field

means the after-tax costs (as specified in

§ 203.89(a)) of exploration,

development, and production that you

incur after the date of first discovery on

the field and before the date we receive

your complete application for royalty

relief. Sunk costs on an expansion

project or development project means,

and on an authorized field includes, the

after-tax costs of the discovery well

qualified as producible under 30 CFR

part 250, subpart A. In no case does

sunk cost include any pre-discovery

activity costs or lease acquisition and

holding costs such as cash bonus and

rental payments. Discovery well costs

include any tangible costs directly

related to the well that you incurred

prior to the discovery date. We count

pre-application costs on an unescalated,

after-tax basis.

* * * * *

3. Section 203.2 is revised to read as

follows:

§ 203.3 When can I get royalty relief?

We can reduce or suspend royalties

for Outer Continental Shelf (OCS) leases

or projects that meet the criteria in the

following table.

If you have a lease— And if you— Then we may grant you—

(a) Whose earnings cannot sustain production

(End-of-life lease).

Would abandon otherwise potentially recoverable resources but seek to increase production significantly by operating beyond the

point at which the lease is economic under

the existing royalty rate.

A reduced royalty rate on current monthly production and a higher royalty rate on additional monthly production. (See §§ 203.50

through 203.56.)

(b) Located in a designated Gulf of Mexico

(GOM) deep water area, and acquired in a

lease sale before November 38, 1995, or

after November 28, 2000, and you propose in

a DOCD or supplement to expand production

significantly.

Are producing and seek to make a substantial

investment (e.g., a platform or subsea template) to increase ultimate resource recovery from the field or lease (Expansion

project).

A royalty suspension for additional production

large enough to make the project economic.

(See §§ 203.60 through 203.79.)

(c) Located in a designated GOM deep water

area and acquired in a lease she held before

November 28, 1995 (Pre-Act lease).

Are on a field from which no current pre-Act

lease produced (other than test production)

before November 28, 1995 (Authorized

field).

A royalty suspension for a minimum production volume plus any additional volume

needed to make the field economic. (See

§§ 203.60 through 203.79.)

(d) Located in a designated GOM deep water

area and acquired in a lease sale held after

November 28, 2000.

Have not produced and can demonstrate that

the suspension volume in your lease is not

enough to make development economic

(Development project).

A royalty suspension for a minimum production volume plus any additional volume

needed to make your project economic.

(See §§ 203.60 through 203.79.)

(e) Where royalty relief would increase production significantly or, in certain areas of the

GOM, would enable development.

Are not eligible to apply for end-of-life or deep

water royalty relief, but show us you meet

certain eligibility conditions.

A royalty reduction in a size or duration that

makes your lease or project economic.

(See §§ 203.80.)

4. Section 203.4 is revised to read as

follows:

§ 203.4 How to do the provisions in this

part apply to different types of leases and

projects?

The tables in this section summarize

how similar provisions of this part

apply in different situations.

(a) Information elements required for

applications in §§ 203.51, 205.62, and

203.81 through 203.89.

Information elements End-of-life

lease

Deep water

Expansion

project Pre-act lease Developmentproject

(1) Administrative information report ....................................................................... XXXX

(2) Net revenue and relief justification report (prescribed format) .......................... X ...................... ...................... ......................

(3) Economic viability and relief justification report (Royalty Suspension Viability

Program (RSVP) model inputs justified with geological and geophysical

(G&G), Engineering, Production, & Cost reports) ............................................... ...................... X X X

(4) G&G report ......................................................................................................... ...................... X X X

(5) Engineering report .............................................................................................. ...................... X X X

(6) Production report ................................................................................................ ...................... X X X

(7) Deep water cost report ...................................................................................... ...................... X X X

69270 Federal Register / Vol. 65, No. 222 / Thursday, November 16, 2000 / Proposed Rules

(b) Confirmation elements required to retain royalty relief in §§ 203.70, 203.81 and 203.90 through 203.91.

Confirmation elements End-of-life

lease

Deep water

Expansion

project Pre-act lease Developmentproject

(1) Fabricator’s confirmation report ......................................................................... ...................... X X X

(2) Post-production development report approved by an independent certified

public accountant (CPA) ...................................................................................... ...................... X X X

(c) Prerequisites for approval of relief in §§ 203.50, 203.52, 203.60 and 203.67.

Approval conditions End-of-life

lease

Deep water

Expansion

project Pre-act lease Developmentproject

(1) At least 12 of the last 15 months have the required level of production .......... X ...................... ...................... ......................

(2) Already producing .............................................................................................. X ...................... ...................... ......................

(3) Well can produce ............................................................................................... ...................... X X X

(4) Royalties for qualifying months exceed 75% of net revenue (NR) ................... X ...................... ...................... ......................

(5) Substantial investment on a pre-Act lease (e.g., platform, subsea template) ... ...................... X ...................... ......................

(6) Determined to be economic only with relief ....................................................... ...................... X X X

(d) Prerequisites for a redetermination in §§ 203.52 and 203.74 through 203.75.

Redetermination conditions End-of-life

lease

Deep water

Expansion

project Pre-act lease Developmentproject

(1) After 12 months under current rate, criteria same as for approval ................... X ...................... ...................... ......................

(2) For material change in geologic data, prices, costs, or available technology ... ...................... X X X

(e) Characteristics of relief in §§ 203.53 and 203.69.

Relief rate and volume End-of-life

lease

Deep water

Expansion

project Pre-act lease Developmentproject

(1) One-half pre-application effective lease rate on the qualifying amount, 1.5

times pre-application effective lease rate on additional production up to twice

the qualifying amount, and the preapplication effective lease rate for any larger

volumes ................................................................................................................ X ...................... ...................... ......................

(2) Qualifying amount is the average monthly production for 12 qualifying months X ...................... ...................... ......................

(3) Zero royalty rate on the suspension volume and the original lease rate or

higher on additional production ............................................................................ ...................... X X X

(4) Suspension volume is at least 17.5, 52.5 or 87.5 million barrels of oil equivalent (MMBOE) ...................................................................................................... ...................... ...................... X ......................

(5) Suspension volume is at least the minimum set in the lease ........................... ...................... ...................... ...................... X

(6) Amount needed to become economic ............................................................... ...................... X X X

(f) Provisions for discontinuing relief in §§ 203.54 and 203.78.

Full royalty resumes when End-of-life

lease

Deep water

Expansion

project Pre-act lease Developmentproject

(1) Average NYMEX price for last 12 months is at least 25 percent above the

average for the qualifying months. ...................................................................... X ...................... ...................... ......................

(2) Average NYMEX price for last calendar year exceeds $28/bbl or $3.50/mcf,

escalated by the gross domestic product (GDP) deflator since 1994. ................ ...................... X X ......................

(3) Average prices for designated periods exceed levels we specify in the lease

document. ............................................................................................................. ...................... X ...................... X

(g) Provisions for ending or reducing relief in §§ 203.55 and 203.76 through 203.77.

Relief Withdrawn or Reduced End-of-life

lease

Deep water

Expansion

project Pre-act lease Developmentproject

(1) If recipient requests. ........................................................................................... XXXX

Federal Register / Vol. 65, No. 222 / Thursday, November 16, 2000 / Proposed Rules 69271

Relief Withdrawn or Reduced End-of-life

lease

Deep water

Expansion

project Pre-act lease Developmentproject

(2) Royalty rate is at the effective rate for the most recent 12 of past 15 months

with qualifying amounts of production. ................................................................ X ...................... ...................... ......................

(3) Conditions that we may specify in the approval letter in individual cases that

actually occur. ...................................................................................................... X ...................... ...................... ......................

(4) Recipient does not submit post-production report that compares expected to

actual costs. ......................................................................................................... ...................... X X X

(5) Recipient changes development system. .......................................................... ...................... X X X

(6) Recipient excessively delays starting fabrication ............................................... ...................... X X X

(7) Recipient spends less than 80 percent of proposed pre-production costs prior

to start of production ............................................................................................ ...................... X X X

(8) Amount of relief volume is produced ................................................................. ...................... X X X

5. Section 203.60 is revised to read as

follows:

§ 203.60 Who may apply for deep water

royalty relief?

Under conditions in §§ 203.61(b) and

203.62, you may apply for royalty relief

if:

(a) You are a lessee of a lease in water

at least 200 meters deep in the GOM and

lying wholly west of 87 degrees, 30

minutes West longitude;

(b) We have assigned your lease to a

field (as defined in § 203.0); and

(c) You either:

(1) Hold a pre-act lease on an

authorized field (as defined in § 203.0)

or

(2) Propose an expansion project (as

defined in § 203.0) or

(3) Propose a development project (as

defined in § 203.0).

6. § 203.62, the introductory sentence

and paragraph (c) are revised to read as

follows:

§ 203.62 How do I apply for relief?

You must send a complete application

and the required fee to the MMS

Regional Director for the GOM.

* * * * *

(c) Sections 203.81, 203.83, and

203.85 through 203.89 describe what

these reports must include. The MMS

regional office for the GOM will guide

you on the format for the required

reports.

7. In § 203.63, the following changes

are made:

A. The introductory paragraph is

redesignated (a) and is revised as set

forth below.

B. Paragraphs (a), (b), and (c)

following the introductory paragraph

are redesignated paragraphs (1), (2), and

(3).

C. A new paragraph (b) is added as set

forth below.

§ 203.63 Does my application have to

include all leases in the field?

(a) For authorized fields, we will

accept only one joint application for all

leases that are part of the designated

field on the date of application, except

as provided in paragraph (a)(3) of this

section and § 203.64. However, we will

evaluate all acreage that may eventually

become part of the authorized field.

Therefore, if you have any other leases

that you believe may eventually be part

of the authorized field, you may submit

data for these leases according to

§ 203.81.

* * * * *

(b) No, if your application seeks only

project relief.

8. In § 203.64, the section heading and

the first sentence in the introductory

paragraph are revised to read as follows:

§ 203.64 How many applications may I file

on a field or a development project?

You may file one complete

application for royalty relief during the

life of the field or for a specific

development project. * * *

* * * * *

9. In § 203.65 paragraph (b) is revised

to read as follows:

§ 203.65 How long will MMS take to

evaluate my application?

* * * * *

(b) We will evaluate your first

application on a field or project within

180 days and evaluate a redetermination

under § 203.75 within 120 days after we

determine that is is complete.

* * * * *

10. Section 203.66 is revised to read

as follows:

§ 203.66 What happens if MMS does not

act in the time allowed?

If we do not act within the timeframes

established under § 203.65, the

conditions in the following table aply.

If you apply for royalty relief

for— And we do not decide within the time specified— As long as you—

(a) An authorized field ........ You get the minimum suspension volumes specified in § 203.69 ................................ Abide by §§ 203.70 and

203.76.

(b) An expansion project ..... You get a royalty suspension for the first year of production ...................................... Abide by §§ 203.70 and

203.76.

(c) A development project ... You get a royalty suspension for production during the number of months that a decision is delayed beyond the stipulated timeframes set by § 203.65, plus all the

royalty suspension volume for which you qualify.

Abide by §§ 203.70 and

203.76.

11. Section 203.67 is revised to read

as follows:

§ 203.67 What economic criteria must I

meet to get royalty relief on an authorized

field or project?

We will not approve applications if

we determine that royalty relief cannot

make the field or project economically

viable. Your field or proejct must be

uneconomic while you are paying

royalties and must become economic

with royalty relief.

12. In § 203.68, paragraph (b) is

revised to read as follows:

69272 Federal Register / Vol. 65, No. 222 / Thursday, November 16, 2000 / Proposed Rules

§ 203.68 What pre-application costs will

MMS consider in determining economic

viability?

* * * * *

(b) We will consider sunk costs

(allowable expenditures on and in some

cases after the discovery well as

specified in § 203.89(a)) according to the

following table:

We will When determining

(1) Include sunk costs ............................ whether a field that includes a pre-Act lease which has not produced, other than test production, before the application or redetermination submission date needs relief to become economic.

(2) Not include sunk costs ..................... whether an authorized field or project can become economic with any relief (see § 203.67).

(3) Not include sunk costs ..................... how much suspension volume is necessary to make the field or project economic (see § 203.69(c)).

(4) Include sunk costs for the discovery

well only.

whether a development project or an expansion project needs relief to become economic.

13. In § 203.69, the introductory

paragraph and paragraphs (b) through

(e) are revised and paragraph (f) is

added to read as follows:

§ 203.69 If my application is approved,

what royalty relief will I receive?

If we approve your application, we

will not collect royalties on a specified

suspension volume for your field.

Suspension volumes include volumes

allocated to a lease under an approved

unit agreement, but exclude any

volumes of production that are not

normally royalty-bearing under the lease

or the regulations of this chapter (e.g.,

fuel gas).

* * * * *

(b) For development projects, any

relief we grant applies only to project

wells and replaces the royalty

suspension volume with which we

issued your lease. If your project is

economic given the royalty suspension

volume with which we issued your

lease, we will reject the application.

Otherwise, the minimum royalty

suspension volumes:

(1) For RS leases, is the sum of the

volume suspensions with which we

issued the RS leases participating in the

application plus 10 percent of the most

likely resource size we agree is

reasonable for your project; and

(2) For other deep water leases issued

in sales after November 28, 2000, is 10

percent of the most likely resource size

we agree is reasonable for your project.

(c) If the application for the field

includes pre-Act or eligible leases in

different categories of water depth, we

apply the minimum royalty suspension

volume for the deepest such lease then

assigned to the field. We base the water

depth and makeup of a field on the

water-depth delineations in the

‘‘Royalty Suspension Areas Map’’ and

the ‘‘Field Names Master List’’ and

updates in effect at the time your

application is deemed complete. These

publications are available from the

MMS Regional Office for the GOM.

(d) You will get a royalty suspension

volume above the minimum if we

determine that you need more to make

the field or development project

economic.

(e) For expansion projects, the

minimum suspension volumes equal 10

percent of the most likely resource size

we agree is reasonable for your project

plus any suspension volumes required

according to § 203.66. If we determine

that your expansion project may be

economic only with more relief, we will

determine and grant you the royalty

suspension volume necessary to make

the project economic.

(f) The royalty suspension volume

applicable to specific leases will

continue through the end of the month

in which cumulative production reaches

that volume. The cumulative production

is from all the leases in the authorized

field or project that are entitled to share

the royalty suspension volume.

14. Section 203.70 is revised to read

as follows:

§ 203.70 What information must I provide

after MMS approves relief?

You must submit reports to us as

indicated in the following table.

Sections 203.81, 203,90, and 203.91

describe what these reports must

include. The MMS regional office for

the GOM will tell you the formats.

Required report When due to MMS Due date extensions

(a) Fabricator’s confirmation report .................... Within 18 months after approval of relief ........ MMS Director may grant you an extension

under § 203.79(c) for up to 6 months.

(b) Post-production report .................................. Within 120 days after the start of production

that is subject to the approved royalty suspension volume.

With acceptable justification from you, MMS

Regional Director for the GOM may extend

due date up to 30 days.

15. In § 203.71, the introductory

paragraph and paragraphs (a) through

(c) are revised to read as follows:

§ 203.71 How does MMS allocate a field’s

suspension volume between my lease and

other leases on my field?

The allocation depends on when

production occurs, when we issued the

lease, when we assigned it to the field,

and whether we award the volume

suspension by an approved application

or establish it in the lease terms as

prescribed in this section.

(a) If your authorized field has an

approved royalty suspension volume

under §§ 203.67 and 203.69, we will

suspend payment of royalties on

production from all applying leases in

the field until their cumulative

production equals the approved volume.

The following conditions also apply:

If— Then— And—

(1) We assign an eligible lease to your field

after we approve relief.

We will not change your field’s royalty suspension volume.The assigned lease(s) may share in any remaining royalty relief.

Federal Register / Vol. 65, No. 222 / Thursday, November 16, 2000 / Proposed Rules 69273

If— Then— And—

(2) We assign a pre-Act or post-2000 deep

water lease to your field after we approve

your application.

We will not change your field’s royalty suspension volume.The assigned lease(s) may share in any remaining royalty relief by filing the short-form

application specified in § 203.83 and authorized in § 203.82. An assigned RS lease

also gets any portion of its royalty suspension volume remaining even after the field

has produced the approved relief volume.

(3) We assign another lease(s) that you operate to your field while we are evaluating your

application, you agree to toll the evaluation

clock until you modify your application to be

consistent with the new field, and we have an

additional 60 days to review the new information.

We will change your field’s minimum suspension volume if the assigned lease is a preAct or eligible lease entitled to a larger minimum or automatic suspension volume.The assigned lease(s) may share the royalty—suspension we grant to the new field.

If you do not agree to toll, we will reject

your application due to inadequate information. But, an eligible lease(s) we assign to

the field keeps its automatic suspension

volume.

(4) We assign another operator’s lease to your

field while we are evaluating your application,

you both agree to toll the evaluation clock

until both of you modify your application to be

consistent with the new field, and we have an

additional 60 days to review the new information.

We will change your field’s minimum suspension volume provided the assigned lease

joins the application and is entitled to a

larger minimum suspension volume.

The assigned lease(s) may share the royalty

suspension we grant to the new field. If you

do not agree to toll, the other operator’s

lease retains any suspension volume it has

or may share in any relief that we grant by

filing the short form application specified in

§ 203.83 and authorized in § 203.82.

(5) We assign a lease to your field before you

submitted the royalty relief application.

We will not change your field’s royalty suspension volume.The assigned lease will not share in the relief

if it did not participate in the application.

(6) We reassign a well on a pre-Act, eligible, or

post-2000 deep water lease to another field.

The past production from the well counts toward the royalty suspension volume of the

field to which we assign the well.

The past production from that well will not

count toward any royalty suspension volume granted to the field from which we reassigned it.

(b) If your authorized field has a

royalty suspension volume established

under § 260.111 of this chapter (i.e., a

field with a pre-Act lease where an

eligible lease starts production first), we

will suspend payment of royalties on

production from all eligible leases in the

field until their cumulative production

equals the established volume. The

following conditions also apply:

If— Then— And—

(1) We assign another eligible lease to your

field.

Your field’s royalty suspension volume does

not change.

The assigned lease may share in any remaining royalty relief.

(2) We assign and RS lease to your field .......... Your field’s royalty suspension volume does

not change.

The assigned lease gets only the volume suspension with which we issued it, and its

production volume counts against the field’s

royalty suspension volume.

(3) We assign a pre-Act lease without royalty

suspension to your field.

Your field’s royalty suspension volume does

not change.

The assigned lease shares none of the volume suspension, and its production does

not count as part of the suspension volume.

(4) A pre-Act or post-2000 deep water lease

applies (along with the other leases in the

field) and qualifies (subject to any suspension

volume in the lease) for royalty relief under

§§ 203.67 and 203.69.

Your field’s royalty suspension volume may

increase or stay the same, but will not diminish.

All leases in the field share the royalty suspension volume if we approve the application; or the RS leases in the field keep their

respective volumes if we reject the application.

(c) This paragraph applies to a project

with more than one lease. The royalty

suspension volume for each lease equals

that lease’s actual production from the

project (or production allocated under

an approved until agreement) until total

production for all leases in the project

equals the project’s approved royalty

suspension volume.

* * * * *

16. In § 203.74, the introductory

paragraph is revised, paragraph (b) and

(c) are revised and redesignated

paragraphs (c) and (d), and a new

paragraph (b) is added to read as

follows:

§ 203.70 When will MMS reconsider its

determination?

You may request a redetermination

after we withdraw approval or after you

renounce royalty relief. Under certain

conditions you may also request a

redetermination if we deny your

application or if you want your

approved royalty suspension volume to

change. In these instances, to be eligible

for a redetermination, at least one of the

following of our conditions must occur.

* * * * *

(b) You demonstrate in your new

application that a technology not

considered or deemed feasible in the

original application most efficiently

develops this field or lease.

(c) Your current reference price

decreases by more than 25 percent from

your base reference price as determined

under this paragraph.

(1) Your current reference price is a

weighted average of daily closing prices

on the NYMEX for light sweet crude oil

and natural gas over the most recent full

12 calendar months;

(2) Your base reference price is a

weighted average of daily closing prices

on the NYMEX for oil and gas for the

most recent full 12 calendar months

preceding the date of your most recently

approved application for this royalty

relief; and

(3) The weighting factors are the

proportions of the total production

69274 Federal Register / Vol. 65, No. 222 / Thursday, November 16, 2000 / Proposed Rules

volume (in BOE) for oil and gas

associated with the most likely scenario

(identified in §§ 203.85 and 203.88)

from your most recently approved

application for his royalty relief.

(d) Before starting to build your

development and production system,

you have revised your estimated

development costs, and they are more

than 120 percent of the eligible

development costs associated with the

most likely scenario from you most

recently approved application for this

royalty relief.

17. In § 203.76, paragraphs (a), (b),

and (c) are revised to read as follows:

§ 203.76 When might MMS withdraw or

reduce the approved size of my relief?

* * * * *

(a) You change the type of

development system proposed in your

application (e.g., change from a fixed

platform to floating production system,

an independent development and

production system to one with subsea

wells tied back to a host production

facility, etc.).

(b) You do not start building the

proposed development and production

system within 18 months of the date we

approved your application, unless the

MMS Director grants you an extension

under § 203.79(c). If you start building

the proposed system and then suspend

its construction before completion, and

you do not restart continuous building

of the proposed system within 18

months of our approval, we will

withdraw the relief we granted.

(c) Your actual development costs are

less than 80 percent of the eligible

development costs estimated in your

application’s most likely scenario, and

you do not report that fact in your postproduction development report

(§ 203.70). Development costs are those

expenditures defined in § 203.89(b)

incurred between the application

submission date and start of production.

If you report this fact in the postproduction development report, you

may retain the lesser of 50 percent of the

original royalty suspension volume or

50 percent of the most likely size of

producible resources anticipated in your

application.

* * * * *

18. Section 203.77 is revised to read

as follows:

§ 203.77 May I voluntarily give up relief if

conditions change?

Yes, by sending a letter to this effect

to the MMS Regional Director for the

GOM.

19. In § 203.78, the introductory

paragraph and paragraph (f) are revised

to read as follows:

§ 203.78 Do I keep relief if prices rise

significantly?

If prices rise above a base price for

light sweet crude oil or natural gas, set

by statute for pre-Act leases, or in your

original lease agreement for post-2000

deep water leases, you must pay full

royalties as prescribed in this section.

* * * * *

(f) We change the prices referred to in

paragraphs (a), (b), and (d) of this

section during each calendar year after

1994. For pre-Act leases, these prices

change by the percentage that the

implicit price deflator for the gross

domestic product changed during the

preceding calendar year. For post-2000

deep water leases, these prices change

as specified in the leasing instrument

and in the Notice of Sale under which

we issued the lease.

20. Section 203.80 is added to read as

follows:

§ 203.80 When can I get royalty relief if I

am not eligible for end-of-life or deep water

royalty relief?

We may grant special royalty relief

when it serves the statutory purposes

summarized in § 203.1, and our formal

relief programs provide inadequate

encouragement to increase production

or development. Before you may apply

for special royalty relief, we must agree

that your lease or project has two or

more of the following characteristics.

(a) The lease has produced for a

substantial period and the lessee can

recover significant additional resources.

(b) Valuable facilities (e.g., a platform

or pipeline that would be removed upon

lease relinquishment) exist on the lease

that we do not expect a successor lessee

to use.

(c) A substantial risk exists that no

new lessee will recover the resources.

(d) The lessee made major efforts to

reduce operating costs too recently to

use the formal program for royalty relief

(e.g., recent significant change in

operations).

(e) Circumstances beyond the lessee’s

control, other than water depth,

preclude reliance on one of the existing

royalty relief programs.

21. In § 203.81, paragraphs (a) and (c)

are revised to read as follows:

§ 203.81 What supplemental reports do

royalty-relief applications require?

(a) You must send us the

supplemental reports listed in the

following table that apply to your field.

§§ 203.83 through 203.91 describe these

reports in detail.

Required reports End-of-life

lease

Deep water

Expansion

project Pre-act lease Developmentproject

(1) Administrative information report ....................................................................... XXXX

(2) Net revenue & relief justification report ............................................................. X ...................... ...................... ......................

(3) Economic viability & relief justification report (RSVP model inputs justified by

other required reports) ......................................................................................... ...................... X X X

(4) G&G report ......................................................................................................... ...................... X X X

(5) Engineering report .............................................................................................. ...................... X X X

(6) Production report ................................................................................................ ...................... X X X

(7) Deep water cost report ...................................................................................... ...................... X X X

(8) Fabricator’s confirmation report ......................................................................... ...................... X X X

(9) Post-production development report .................................................................. ...................... X X X

* * * * *

(c) With your application and postproduction development report, you

must submit an additional report

prepared by an independent CPA that:

(1) Assesses the accuracy of the

historical financial information in your

report and

(2) Certifies that the content and

presentation of the financial data and

information conform to our most recent

guidelines on royalty relief, with

primary regard to including only

eligible costs that are incurred during

the qualification months and shown in

the proper format.

* * * * *

Federal Register / Vol. 65, No. 222 / Thursday, November 16, 2000 / Proposed Rules 69275

22. In § 203.83, paragraph (c) is

revised to read as follows:

§ 203.83 What is in an administrative

information report?

* * * * *

(c) Lessee’s well designation, the API

number, and the location of each well

that has been drilled on the field or

lease or project (not required for non-oil

and gas leases);

* * * * *

23. In § 203.86, the following changes

are made:

A. The word ‘‘and’’ is removed at the

end of paragraph (b)(6).

B. The ‘‘.’’ is removed and ‘‘; and’’ is

added at the end of paragraph (b)(7).

C. Paragraph (b)(8) is added.

D. Paragraph (c)(4) is revised.

E. The word ‘‘and’’ is removed at the

end of paragraph (d)(6).

F. The ‘‘.’’ is removed and ‘‘; and’’ is

added at the end of paragraph (d)(7).

G. Paragraph (d)(8) is added.

The additions and revisions in

changes C, D, and G read as follows:

§ 203.86 What is in G&G report?

* * * * *

(b) * * *

(8) A table listing the wells/

completions and indicating which sands

and fault blocks will be targeted for

completion/recompletion.

(c) * * *

(4) an explanation for excluding the

reservoirs you are not planning to

develop.

(d) * * *

(8) Reserve/resource distribution by

reservoir.

* * * * *

24. In § 203.87, paragraphs (a)(1) and

(d) are revised to read as follows, and

paragraphs (d)(1) and (d)(2) are

removed.

§ 203.87 What is in an engineering report?

* * * * *

(a) * * *

(1) Its size along with basic design

specifications and drawings and

* * * * *

(d) A discussion of any plans for

multi-phase development which

includes the conceptual basis for

developing in phases and goals or

milestones required for starting later

phases.

* * * * *

25. In § 203.89, paragraph (a) is

revised to read as follows:

§ 203.89 What is in an engineering report?

* * * * *

(a) On an authorized field, sunk costs

which are all your eligible postdiscovery exploration, development,

and production expenses (no third party

costs), and include the eligible costs of

the discovery well on the field. On an

expansion project or a development

project, sunk costs are just the eligible

costs of the discovery well for the

project. Report them in nominal dollars

and only if you have documentation.

We count sunk costs in an evaluation

(specified in § 203.68) as after-tax

expenses, using nominal dollar

amounts.

* * * * *

26. In § 203.91, a new last sentence is

added to read as follows:

§ 203.91 What is in an engineering report?

* * * Also, you must have this

report certified by an independent CPA

according to § 203.81(c).

[FR Doc. 00–29372 Filed 11–15–00; 8:45 am]

BILLING CODE 4310–MR–M

ENVIRONMENTAL PROTECTION

AGENCY

40 CFR Part 52

[MA–081–7211b; A–1–FRL–6897–5]

Approval and Promulgation of Air

Quality Implementation Plans;

Massachusetts; Enhanced Motor

Vehicle Inspection and Maintenance

Program

AGENCY: Environmental Protection

Agency (EPA).

ACTION: Proposed rule.

SUMMARY: The EPA is proposing to

approve a State Implementation Plan

(SIP) revision submitted by the

Commonwealth of Massachusetts. This

revision establishes and requires the

implementation of an enhanced

inspection and maintenance program. In

the Final Rules Section of this Federal

Register, EPA is approving the

Commonwealth’s SIP submittal as a

direct final rule without prior proposal

because the Agency views this as a

noncontroversial submittal and

anticipates no adverse comments. A

detailed rationale for the approval is set

forth in the direct final rule. If no

relevant adverse comments are received

in response to this action, no further

activity is contemplated. If EPA receives

relevant adverse comments, the direct

final rule will be withdrawn and all

public comments received will be

addressed in a subsequent final rule

based on this proposed rule. EPA will

not institute a second comment period.

Any parties interested in commenting

on this action should do so at this time.

Please note that if EPA receives adverse

comment on an amendment, paragraph,

or section of this rule and if that

provision may be severed from the

remainder of the rule, EPA may adopt

as final those provisions of the rule that

are not the subject of an adverse

comment.

DATES: Written comments must be

received on or before December 18,

2000.

ADDRESSES: Comments may be mailed to

David Conroy, Unit Manager, Air

Quality Planning, Office of Ecosystem

Protection (mail code CAQ), U.S.

Environmental Protection Agency, EPANew England, One Congress Street,

Suite 1100, Boston, MA 02114–2023.

Copies of the State submittal and EPA’s

technical support document are

available for public inspection during

normal business hours, by appointment

at the Office of Ecosystem Protection,

U.S. Environmental Protection Agency,

EPA-New England, One Congress Street,

11th floor, Boston, MA and Division of

Air Quality Control, Department of

Environmental Protection, One Winter

Street, 8th Floor, Boston, MA 02108.

FOR FURTHER INFORMATION CONTACT:

Peter Hagerty, (617) 918–1049.

SUPPLEMENTARY INFORMATION: For

additional information, see the direct

final rule which is located in the Rules

Section of this Federal Register.

Dated: October 27, 2000.

Mindy S. Lubber,

Regional Administrator, EPA-New England.

[FR Doc. 00–29219 Filed 11–15–00; 8:45 am]

BILLING CODE 6560–50–P

ENVIRONMENTAL PROTECTION

AGENCY

40 CFR Part 81

[Docket WA–00–01; FRL–6902–6]

Clean Air Act Reclassification; Wallula,

Washington Particulate Matter (PM10)

Nonattainment Area

AGENCY: EPA.

ACTION: Proposed rule.

SUMMARY: EPA proposes to determine

that the Wallula nonattainment area has

not attained the National Ambient Air

Quality Standards for particulate matter

with an aerodynamic diameter of less

than or equal to 10 microns (PM10) by

the attainment date of December 31,

1997, as required by the Clean Air Act.

EPA’s proposed finding is based on

EPA’s review of monitored air quality

data reported for the years 1995 through

1999. If EPA takes final action on this

proposal, the Wallula PM10