Federal Register / Vol. 61, No. 106 / Friday, May 31, 1996 / Rules and Regulations 27263

accounting activities are performed, at the

print shop located in the zone. K, on

occasion, uses its equipment (including its

trucks) and employees to deliver large print

jobs to customers who reside outside of the

zone. So long as K is able to establish that

its trucks are used in the zone at least 85%

of the time and its employees perform at least

85% of services for K in the zone, K meets

the requirements of sections 1397B(b)(3) and

(5).

Example 5. Treatment as a separately

incorporated business. The facts are the same

as in Example 4 except that six years after the

issue date of the enterprise zone facility

bonds, K determines to expand its operations

to a second location outside of the

boundaries of the zone. Although the

expansion would result in the failure of K to

meet the tests of 1397B(b), K, using a

reasonable allocation method, allocates

income and activities to its operations within

the zone and has evidence of these

allocations sufficient to establish compliance

with the requirements of paragraphs (b)

through (f) of this section. The bonds will not

fail to be enterprise zone facility bonds

merely because of the expansion.

Example 6. Treatment of pooled financing

bond programs. Authority L issues bonds in

the aggregate principal amount of $5,000,000

and loans the proceeds to Bank M pursuant

to a loans-to-lenders program. M does not

meet the definition of enterprise zone

business contained in section 1397B. Prior to

the issue date of the bonds, L held a public

hearing regarding issuance of the bonds for

the loans-to-lenders program, describing the

projects of identified borrowers to be

financed initially with $4,000,000 of the

proceeds of the bonds. The applicable elected

representative of L approved issuance of the

bonds subsequent to the public hearing. The

loan agreement between L and M provides

that the other proceeds of the bonds will be

held by M and loaned to borrowers that

qualify as enterprise zone businesses,

following a public hearing and approval by

the applicable elected representative of L of

each loan by M to an enterprise zone

business. None of the loans will be in

principal amounts in excess of $3,000,000.

The loans by M will otherwise meet the

requirements of section 1394. The bonds will

be enterprise zone facility bonds.

Example 7. Original use requirement for

purposes of qualified zone property. City N

issues enterprise zone facility bonds, the

proceeds of which are loaned to Corporation

P to finance the acquisition of equipment. P

uses the proceeds after the zone designation

date to purchase used equipment located

outside of the zone and places the equipment

in service at its location in the zone.

Substantially all of the use of the equipment

is in the zone and is in the active conduct

of a qualified business by P. The equipment

is treated as qualified enterprise zone

property under section 1397C because P

makes the first use of the property within the

zone after the zone designation date.

Example 8. Principal user. State R issues

enterprise zone facility bonds and loans the

proceeds to Partnership S to finance the

construction of a small shopping center to be

located in a zone. S is in the business of

commercial real estate. S is not an enterprise

zone business, but has secured one anchor

lessee, Corporation T, for the shopping

center. T would qualify as an enterprise zone

business. S will derive 60% of its gross rental

income of the shopping center from T. S does

not anticipate that the remaining rental

income will come from enterprise zone

businesses. T will occupy 60% of the total

rentable space in the shopping center. S can

use enterprise zone facility bond proceeds to

finance the portion of the costs of the

shopping center allocable to T (60%) because

T is treated as the principal user of the

enterprise zone facility bond proceeds.

Example 9. Remedial actions. State W

issues pooled financing enterprise zone

facility bonds, the proceeds of which will be

loaned to several enterprise zone businesses

in the two enterprise communities and one

empowerment zone in W. Proceeds of the

pooled financing bonds are loaned to

Corporation X, an enterprise zone business,

for a term of 10 years. Six years after the date

of the loan, X expands its operations beyond

the empowerment zone and is no longer able

to meet the requirements of section 1394. X

does not reasonably expect to be able to cure

the noncompliance. The loan documents

provide that X must prepay its loan in the

event of noncompliance. W does not expect

to be able to reloan the prepayment by X

within six months of noncompliance. X’s

noncompliance will not affect the

qualification of the pooled financing bonds

as enterprise zone facility bonds if W uses

the proceeds from the loan prepayment to

redeem outstanding enterprise zone facility

bonds within six months of noncompliance

in an amount comparable to the outstanding

amount of the loan immediately prior to

prepayment. X will be denied an interest

expense deduction for the interest accruing

from the first day of the taxable year in which

the noncompliance began.

(q) Effective dates—(1) In general.

Except as otherwise provided in this

section, the provisions of this section

apply to all issues issued after July 30,

1996, and subject to section 1394.

(2) Elective retroactive application in

whole. An issuer may apply the

provisions of this section in whole, but

not in part, to any issue that is

outstanding on July 30, 1996, and is

subject to section 1394.

Approved: May 22, 1996.

Margaret Milner Richardson,

Commissioner of Internal Revenue.

Leslie Samuels,

Assistant Secretary of the Treasury.

[FR Doc. 96–13718 Filed 5–30–96; 8:45 am]

BILLING CODE 4830–01–U

DEPARTMENT OF THE INTERIOR

Minerals Management Service

30 CFR Part 203

RIN 1010–AC13

Royalty Relief for Producing Leases

and Certain Existing Leases in Deep

Water

AGENCY: Minerals Management Service

(MMS), Interior.

ACTION: Interim Rule and Information

Gathering.

SUMMARY: This interim rule establishes

conditions for granting royalty relief on

producing leases through their

conversion to Net Revenue Share (NRS)

leases, provides for suspensions of

royalty payments on certain deep-water

leases issued as the result of a lease sale

held before November 28, 1995, and

defines the information required for a

complete application for royalty relief.

DATES: This interim rule is effective July

1, 1996.

We will consider all comments we

receive by July 30, 1996. We will begin

review of comments at that time and

may not fully consider comments we

receive after July 30, 1996.

ADDRESSES: Mail or hand-carry

comments to the Department of the

Interior; Minerals Management Service;

Mail Stop 4700; 381 Elden Street;

Herndon, Virginia 22070–4817;

Attention: Chief, Engineering and

Standards Branch.

FOR FURTHER INFORMATION CONTACT: Dr.

Marshall Rose, Economic Evaluation

Branch, telephone (703) 787–1536.

SUPPLEMENTARY INFORMATION:

I. Objectives of Royalty Relief

Royalty relief can lead to increased

production of natural gas and oil,

creating profits for lessees and royalty

and tax revenues for the government. By

this rulemaking, the Secretary seeks to

establish economic incentives to

encourage Outer Continental Shelf

(OCS) lessees to incur the expenses or

make the capital investments necessary

to maintain or increase production. To

the extent possible for approved

applications, we will reduce or suspend

royalty payments to permit lessees to

earn a reasonable return on their capital

investment for projects involving new

investment. For projects not involving

new investment, we will provide relief

sufficient to allow an operating profit in

cases where expenses plus royalties

exceed revenues.

The Secretary will implement these

royalty relief provisions in conjunction
27264 Federal Register / Vol. 61, No. 106 / Friday, May 31, 1996 / Rules and Regulations

with his stewardship responsibilities for

the sound management of public lands.

This includes conservation of resources,

obtaining a fair return to the public on

OCS resources, and ensuring that all

OCS development is safe and consistent

with sound environmental standards.

II. Legislative Background

The Secretary has broad legislative

authority to reduce royalty rates on OCS

leases. The Outer Continental Shelf

Lands Act (OCSLA), as amended, (43

U.S.C. 1337(a)(3)(A)) states:

‘‘The Secretary may, in order to

promote increased production on the

lease area, through direct, secondary, or

tertiary recovery means, reduce or

eliminate any royalty or net profit share

set forth in the lease for such area.’’

This provision gives the Secretary

authority to reduce royalties on

producing leases upon application by a

lessee. Leases may be in shallow or deep

water and may be located in any area of

the OCS. Relief must be applied for,

justified, and granted on a case-by-case

basis.

On November 28, 1995, President

Clinton signed Public Law 104–58,

which included the Deep Water Royalty

Relief Act (DWRRA). Section 302 of the

DWRRA amends the OCSLA authority

to allow the Secretary to grant relief on

both producing and nonproducing

leases and on categories of leases, rather

than only on a case-by-case basis, in

order to promote development, increase

production, or encourage marginal

production on Gulf of Mexico leases

lying west of 87 degrees, 30 minutes

West longitude. This rulemaking does

not include regulations to implement

the expanded discretionary authority to

grant royalty relief in 43 U.S.C.

1337(a)(3)(B). Regulations for that

purpose may be included in a future

rulemaking.

In addition, the DWRRA also contains

three other major provisions related to

leases issued as a result of sales held

before and after the date of the

DWRRA’s enactment.

First, section 303 establishes a new

bidding system that allows the Secretary

to offer tracts with royalty suspensions

for a period, volume, or value of

production. On February 2, 1996, we

published a final rule modifying the

regulations for the bidding systems we

use to offer OCS tracts for lease (61 FR

3800). Portions of that rule in 30 CFR

260.110(a)(7) address the new bidding

system authorized by section 303 of the

DWRRA.

Second, section 304 mandates that all

tracts offered within 5 years of the date

of enactment in water depths of 200

meters or more in the Gulf of Mexico

west of 87 degrees, 30 minutes West

longitude, must be offered under the

new bidding system permitted by

section 303. The Secretary must offer

such tracts with a specified minimum

royalty suspension volume based on

water depth. We published an interim

rule in the Federal Register on March

25, 1996 (61 FR 12022), specifying the

terms under which the Secretary will

make royalty suspensions available for

new deep-water leases issued as the

result of sales held after November 28,

1995.

Third, again in section 302, the

DWRRA provides that ‘‘new

production,’’ as defined in that Act,

from a lease or unit in existence on the

date of its enactment, and in water

depths of 200 meters or greater in the

Gulf of Mexico west of 87 degrees, 30

minutes West longitude, does not

qualify for royalty suspensions if the

Secretary determines that the new

production would be economic in the

absence of royalty relief. Otherwise, the

Secretary must determine the volume of

production on which no royalty would

be due in order to make the new

production economically viable. This

determination must be made on a caseby-case basis.

For existing leases or units which had

no royalty bearing production, other

than test production, before November

28, 1995, and which qualify for relief

under section 302, the following

minimum volumes of production are

not subject to the royalty obligation

specified in the lease:

• 17.5 million barrels of oil

equivalent (MMBOE) for leases in 200 to

400 meters of water,

• 52.5 MMBOE for leases in 400 to

800 meters of water, and

• 87.5 MMBOE for leases in more

than 800 meters of water.

These leases may qualify for a larger

suspension volume if they would not be

economic at the minimum royalty

suspension volume specified by the

DWRRA.

We also may grant a royalty

suspension volume for production

resulting from lease development

activities pursuant to a Development

Operations Coordination Document

(DOCD), or a supplement to an

approved DOCD, approved by the

Secretary after November 28, 1995, that

would expand production significantly

beyond the level anticipated in a prior

DOCD. In this case, we will grant the

royalty suspension volume that we

determine to be necessary to make the

new production from the proposed

project economic.

III. The Need for an Interim Rule

The DWRRA requires the Secretary to

issue implementing regulations within

180 days of enactment. We cannot

conduct and complete the usual

proposed notice and comment

rulemaking process to implement this

part of the DWRRA before the statutorily

imposed May 28, 1996, deadline.

However, because the public interest

would be best served by meeting the

deadline and by establishing rules for

these provisions of the DWRRA as soon

as practicable, we are issuing this

interim rule.

Several factors, in combination, have

prevented us from issuing

comprehensive rules through the usual

rulemaking process by the statutory

deadline. The Department of the Interior

was shut down from December 12, 1995,

to January 8, 1996, due to the lack of

funding. Subsequently, MMS offices in

the Washington, DC area were closed

again for several days because of the

‘‘blizzard of ’96.’’

These closings consumed critical time

that would have been used to conduct

the planning and preparation necessary

to define the issues involved and devise

an orderly process for a comprehensive

rulemaking that would allow for as

much advance notice and meaningful

public participation as possible within

the statutory deadline. Because of the

complexity of the issues involved in this

rulemaking, we believe the public

interest would not be served by severely

abbreviating the notice and comment

procedures of the rulemaking process to

meet the May 28, 1996, deadline.

Therefore, we decided the public

interest would be served best by

instituting a multipart rulemaking to

meet the statutory objectives and allow

extensive and meaningful public

participation, consistent with law.

As the first step, we promptly

published an Advance Notice of

Proposed Rulemaking (ANPR) in the

Federal Register on February 23, 1996

(61 FR 6958), and announced our intent

to develop comprehensive regulations

implementing the DWRRA. The ANPR

sought comments and recommendations

to assist us in that process. The

comment period did not close until

April 8, 1996, leaving too little time for

a meaningful proposed notice and

comment rulemaking by May 28, 1996.

We also conducted a public meeting in

New Orleans on March 12 and 13, 1996,

to discuss with interested members of

the public the matters the ANPR

addressed.

We published an interim rule in the

Federal Register on March 25, 1996 (61

FR 12022), specifying the terms under
Federal Register / Vol. 61, No. 106 / Friday, May 31, 1996 / Rules and Regulations 27265

which we will make royalty

suspensions available for new deepwater leases issued as a result of sales

held after November 28, 1995.

As in the case of the interim rule for

royalty suspensions for new deep-water

leases, implementation of the DWRRA’s

provisions for existing leases by the

Congressionally prescribed deadline is

in the public interest. These provisions

should be implemented promptly so

that lessees may proceed with important

investment decisions. Furthermore, as

explained below, failure to issue

implementing regulations by the

prescribed deadline would create a legal

uncertainty under which we might be

required to grant royalty relief to one or

more OCS projects that would not

otherwise qualify. In that situation,

there would be potential losses of

hundreds of millions of dollars in

Federal revenues.

The availability of royalty

suspensions for new production from

existing deep-water leases becomes an

important factor in lessees’ decisions

about whether or not to proceed with

development of oil and gas on their

leases. However, lessees cannot

adequately consider or accurately plan

the potential economic benefits of

royalty relief until we issue regulations

establishing the procedures for granting

a royalty suspension and defining the

data and information required for a

complete application. Respondents to

the ANPR indicated their desire to have

us make this information available to

them as soon as possible.

Lessees are likely, therefore, to delay

investment decisions until we have

implementing regulations in place.

These investments are important to the

national and regional economies and

any delay could adversely impact very

important economic activity. Thus, it is

in the public interest to proceed to issue

an interim rule within the time frame

mandated by Congress.

The establishment of interim

regulations is also necessary so that

lessees can make informed decisions

about whether to proceed with lease

development activities or allow their

leases to expire. Our regulations (30

CFR 250.13) provide that lessees must

engage in drilling, production or wellreworking activities in order to keep

their leases in force beyond the primary

term specified in the lease. If they do

not, then in the absence of production

after the primary term of the lease, their

leases expire at the end of the primary

term or 90 days after drilling activities

cease.

Of the approximately 1,600 leases in

deep water in the Central and Western

Gulf of Mexico, 116 leases are nearing

the end of their primary term. Lessees,

aware that Congress was considering the

enactment of royalty relief legislation,

may have deferred taking action on their

leases so they could properly account

for such relief in calculating project

economics.

However, lessees cannot make the

necessary calculations until we issue

implementing regulations. If we were to

go through the usual rulemaking

process, some leases could reach their

expiration date before final rules are

established. In these cases, some lessees

may allow their leases to expire because

they cannot determine whether or not

their leases will qualify for a royalty

suspension volume. We believe this

situation contradicts the purpose of the

DWRRA and does not serve the public

interest.

Any further delay in issuing even

interim rules may place some leases at

a competitive disadvantage. Fields in

deep water may consist of both new

leases and leases issued as the result of

a lease sale held prior to November 28,

1995. New leases automatically qualify

for a royalty suspension volume. Our

regulations (30 CFR 260.110(d)(6))

provide that in multiple lease fields,

those new leases that first produce the

royalty suspension volume are the ones

that gain the royalty relief.

Therefore, operators of new leases

may proceed with development

activities as soon as possible with the

certainty that they will receive a royalty

suspension volume. Lessees of leases

issued as the result of a lease sale held

prior to November 28, 1995, must wait

until rules are issued before they can

determine if they qualify for relief. By

going through the usual rulemaking

process, lessees of new leases could gain

an advantage over these lessees. We

believe this to be unfair and that the

public interest requires that, to the

extent possible, we fully inform lessees

and create a ‘‘level playing field’’ by

issuing this interim rule.

Upon receipt of an application for

royalty relief under section 302 of the

DWRRA (43 U.S.C. 1337(a)(3)(C)), the

Secretary must determine whether new

production from the lease or unit is

economic in the absence of royalty

relief. If the new production is

determined to be uneconomic, royalty

payments may be suspended on the new

production until the suspension volume

specified in the DWRRA, or such greater

volume as the Secretary determines is

necessary to make the new production

economically viable, is produced. If the

Secretary does not make the

determination within 180 days of

receiving an application and finding

that it is complete, the DWRRA

mandates royalty suspension

automatically, unless the evaluation

period is extended by 30 days, or for

longer than 30 days with the applicant’s

concurrence.

Delaying a rulemaking on this issue

also raises a significant question of

statutory interpretation as to when

lessees may begin submitting

applications for royalty relief. One

possible interpretation is that they could

submit applications for a royalty

suspension volume under the DWRRA

as soon as the Congressional deadline

for the issuance of implementing

regulations passed.

Under this interpretation, unless

sound application requirements and

suspension terms are established by

rulemaking before lessees can begin

submitting applications, some leases or

units could receive automatic royalty

suspensions that would otherwise not

be granted. In such cases, the royalty

relief would unnecessarily penalize the

taxpayer and the Federal Treasury.

These potential losses could amount to

hundreds of millions of dollars. The

issuance of an interim rule and

associated guidelines will avoid

potential problems regarding

interpretation of the DWRRA’s

application provisions.

Thus, prudent public policy and the

national interest dictate that we issue

this interim rule, thereby avoiding the

risk that, however unlikely, the

aforementioned interpretation of the

statute might prevail.

Issuance of this interim rule will not

preclude opportunities for the public to

comment on the issues addressed

herein. We have considered the

comments submitted in response to the

ANPR and in the public meeting, and

we invite comments on this interim

rule. We will also hold another public

meeting if there is significant public

interest to do so. As with the interim

rule on royalty relief for new deep-water

leases, a final rulemaking would include

the provisions covered by this interim

rule. Based on comments received and

experience with initial applications, we

may make changes to the matters this

interim rule addresses when we issue a

final rule that implements all provisions

of the DWRRA.

The following sections discuss the

two types of royalty relief addressed by

this interim rule: first, conversion of

existing producing leases to NRS leases

under the OCSLA’s general royalty rate

reduction authority; and second,

granting of royalty suspension volumes

for certain deep-water leases under the

new OCSLA provisions added by the

DWRRA.
27266 Federal Register / Vol. 61, No. 106 / Friday, May 31, 1996 / Rules and Regulations

IV. Net Revenue Share Leases

Over the years, we have received 19

applications for royalty rate reductions

under the OCSLA statutory provision as

implemented by regulations at 30 CFR

203.50. Of these, we approved 10

applications, we denied 7 applications,

and we still have 2 applications under

review. While this program has

produced worthwhile results, our

experience with it has led us to believe

that its terms and conditions need

clarification and restructuring. We also

found that applicants needed more

information on how to apply for relief,

including the data that must be

submitted for a complete application.

Accordingly on December 14, 1995,

we issued interim ‘‘Guidelines for the

Application, Review, Approval, and

Administration of the Royalty Relief

Program.’’ The guidelines were

developed to provide industry with

clear instructions about how to apply

for royalty relief. The guidelines

streamline and simplify our royalty

relief application process.

This portion of the rulemaking

supplements the guidelines with

additional direction on the data and

information required in applications

and revises 30 CFR 203.50 to be

consistent with this new approach.

Criteria and Basis for Relief

All active leases or units that are

producing or that produced previously

are eligible for royalty relief under this

section.

Royalty relief will be granted to

enable lessees of leases with inadequate

revenues to continue production or to

encourage lessees to make additional

capital investment to expand

production. As a condition of approval,

an applicant must agree to convert its

lease to an NRS lease. The NRS rates

will be calculated to allow lessees a

return on operating expenses or new

capital, as appropriate, while ensuring

protection of Federal revenue interests.

Applications

Lessees of eligible leases may apply

for royalty relief to the appropriate

MMS Regional Director. Applications

should be prepared in accordance with

the December 1995 guidelines,

subsequent updates, and these

regulations. The data and information

required for a complete application

depends on whether the applicant

proposes a continuation or expansion of

current production.

Applications from lessees of marginal

leases with inadequate revenues to

sustain production must include certain

administrative information, justification

for the relief sought, and an NRS

economic viability supplemental report

(§ 203.53(b) and § 203.55).

Applications from lessees of leases

proposing an expansion of production

that would be uneconomic without

royalty relief must contain certain

administrative information, justification

for the relief sought, and four

supplemental reports:

(1) NRS Economic Viability Report;

(2) Geological and Geophysical

Report;

(3) Production Report; and

(4) Engineering Report.

The regulations specify the details of

the required information at § 203.55.

The format for submitting the required

information is presented in the our

guidelines.

Review and Evaluation Criteria

To qualify for relief, we must

determine, based on the application

information, that relief would increase

ultimate recovery of reserves extending

the productive life of the lease by at

least 1 year. Projects that merely

accelerate the rate of production do not

qualify. This approach is consistent

with the OCSLA mandate that royalty

relief should ‘‘promote increased

production on the lease area.’’

For leases with inadequate revenues

to sustain production to qualify for

relief, we must determine that:

(1) Federal royalty payments over the

most recent 12-month period were at

least 75 percent of net revenues; and

(2) Federal royalty payments are

projected to take an increasing share of

net revenues (§ 203.52(c)).

We believe that, under these

conditions, production on most leases is

likely to be terminated unless relief is

available. Thus, to the extent that the

relief provided keeps a lease in

production, one can say that the relief

promoted increased production.

For NRS applications proposing an

investment to expand production, we

will determine if the proposed project is

economic in the absence of royalty

relief. If development of the project

would be economic, then we will deny

the application. If development of the

project would not be economic without

royalty relief, then the royalty will be

converted to a NRS rate sufficient to

make the project economically viable, as

described in the NRS Guidelines

available in the appropriate Regional

Office. In those instances where no

amount of royalty relief would make the

project economic, we will deny the

application. We will not count sunk

costs in making these determinations.

V. Pre-Enactment Deep-Water Leases

Definitions

As used in the interim rule:

Field means an area consisting of a

single reservoir or multiple reservoirs

all grouped on, or related to, the same

general geological structural feature

and/or stratigraphic trapping condition.

There may be two or more reservoirs in

a field that are separated vertically by

intervening impervious strata, or

laterally by local geologic barriers, or

both.

Pre-enactment deep-water lease

(PDWL) means an OCS lease issued as

a result of a lease sale held before

November 28, 1995. The lease must be

in a water depth of at least 200 meters

and in the Gulf of Mexico west of 87

degrees, 30 minutes West longitude.

Project to significantly expand

production (PSEP) means a project

proposed in an approved Supplemental

DOCD that will result in an increase in

ultimate recovery of resources from the

field and that involves a substantial

capital investment (e.g., the addition of

a fixed-leg platform, subsea template

and manifold, tension-leg platform,

multiple well projects, etc.). The project

must be on a PDWL.

Sunk costs means costs (as specified

in § 203.55) of exploration,

development, and production incurred

after the date of first discovery on the

field and prior to the date of application

for royalty relief. Sunk costs also

include the costs of the discovery well

qualified as producible under 30 CFR

250.11.

These terms are defined in 30 CFR

§ 203.50.

Criteria for Consideration of Relief

We will consider an application for

the suspension of royalty payments on

a volume of new production from a

lease if the lease meets three basic

conditions:

• The lease must have been issued as

a result of a lease sale held before

November 28, 1995, the date of

enactment of the DWRRA.

• The lease must be located in water

depths of 200 meters or greater.

• The lease must encompass only

whole blocks lying west of 87 degrees,

30 minutes West longitude in the Gulf

of Mexico.

Units may apply if they include at

least one lease that meets these

conditions, but any royalty suspension

will apply only to those leases in the

unit that meet these conditions.

Basis for Granting Relief

Section 302(C) of the DWRRA states

that an application may be made on the
Federal Register / Vol. 61, No. 106 / Friday, May 31, 1996 / Rules and Regulations 27267

basis of an individual lease or unit. The

term ‘‘unit’’ is not defined in the

DWRRA. A fundamental issue in

implementing the DWRRA is: should

royalty relief for leases or units be based

on some geologic or economic unit,

such as a field?

We faced the same issue when we

published the interim rule for new

leases on March 25, 1996 (61 FR 12022)

which amended § 260.110 to implement

the provisions of section 304 of the

DWRRA. In that instance, new (i.e.,

‘‘eligible’’) leases receive suspension

volumes automatically, without

demonstrating a need for the suspension

to assure economic viability. We have

structured this rule to apply the PDWL

royalty suspension provisions

consistently with the royalty suspension

provisions for new leases. Accordingly,

two principles established in that

interim rule will apply to this rule too.

First, as set forth for new eligible

leases in § 260.110(d), we will allow

only one royalty suspension volume per

new field (i.e., a field not producing

prior to November 28, 1995). We believe

Congress added ‘‘or unit’’ to section 302

of the DWRRA to allow us to evaluate

multi-lease fields. But, in recognition of

the objections raised in response to the

ANPR regarding the suggestion that we

might compel unitization, we will

require leases in multi-lease fields that

are not unitized to submit a joint

application, as discussed below.

We set forth the underlying

justification for a field approach in the

preamble to the interim rule

establishing the royalty suspension

regulations for new deep-water leases

under section 304 of the DWRRA.

Briefly, the minimum royalty

suspension volumes which Congress set

forth in the DWRRA were developed

from technical analysis conducted to

estimate the royalty suspension volumes

needed for capital cost recovery in

developing unproduced oil and gas

fields at various water depths in the

Gulf of Mexico. This helps explain the

fact that the chief Congressional

sponsor, Senator Johnston, expressly

linked the royalty suspension volumes

in the DWRRA to the cost of developing

a field.

Senator Johnston explained that the

legislation was intended only to provide

incentives for drilling leases that would

not otherwise be drilled and to bring

new fields into production:

It is only with respect to those leases that

would not otherwise be drilled, either

existing or future leases, that this

amendment would provide that incentive

* * * The Secretary of the Interior wanted

the incentive to be sufficient but not too

much. That took a lot of negotiating * * *

[The legislation] should bring on at least two

new fields with approximately 150 million

barrels of oil equivalent from existing leases

and it significantly improves the economics

of 10 to 12 possible and probable fields. 141

Cong. Rec. S. 6731 (daily ed., May 16, 1995)

[emphasis added].

This statement strongly indicates that

the DWRRA legislation was not

intended to provide each lease in deep

water the full royalty suspension

volume. Granting royalty suspensions

on a lease basis could result in much

more relief than necessary to bring new

fields into production.

As a hypothetical example, assume a

field in 600 meters of water (the

minimum suspension volume

associated with 600 meters of water is

52.5 MMBOE) consists of two leases.

Assume that our evaluation of the

application under the DWRRA

determines that development of the

field is uneconomic without a

suspension of royalty and that a royalty

suspension of 35 MMBOE is needed to

make development of the field

economically viable. Granting the

royalty suspension volume called for in

the DWRRA to each lease would result

in a total royalty suspension volume of

105 MMBOE, three times the amount

necessary to make development of the

field economically viable.

Thus, to be faithful to the intent of the

DWRRA legislation, the royalty

suspension volumes should be applied

on a field basis, rather than giving each

individual lease a full royalty

suspension volume.

Second, if a PDWL is part of a field

where any current lease produced prior

to November 28, 1995, it cannot receive

a royalty suspension volume from that

field (except that a royalty suspension

may be granted for a lease that

undertakes a significant expansion of

production on a field that produced

before November 28, 1995). Since those

lessees who undertook the initial

production from the field (and can be

said to have taken the most risk) would

not be eligible for a royalty suspension

volume under the DWRRA, neither

should the lessees of leases on that

producing field that begin production

after the DWRRA’s enactment. Under

these circumstances, Congress certainly

recognized that it is not necessary to

encourage production.

We will assign PDWL’s to a field the

same as described in the interim rule for

new deep-water leases. That is, we will

assign a lease to a field when a well on

the lease qualifies as capable of

producing in paying quantities under

the regulations at 30 CFR 250.11. If a

well does not qualify under the rule, we

will assign the lease to a field when

hydrocarbons are first produced from

the lease or when the lease is allocated

production under an approved unit

agreement.

The definition of field is set forth in

30 CFR 203.50. The definition is based

on geology. We issue the OCS

Operations Field Names Master List,

which lists all the tracts in each field on

the Gulf of Mexico OCS each quarter,

with monthly updates.

We recognize that lessees may

occasionally disagree with our

determination that a lease is part of a

particular field. Lessees may appeal

these designations to the Director in the

same manner as bid rejections are

appealed. To appeal a decision that a

lease is part of a particular field, a lessee

must file a written request to the

Director within 15 days of when we

designate the lease as part of a field. The

Director’s response to this request,

either affirming or reversing the earlier

decision, cannot be appealed further

within the Department of the Interior.

The deepest water depth on a lease in

a field at the time an approved

application for a royalty suspension was

submitted establishes the water depth

for that field. The water depth of a lease

is governed by the ‘‘Royalty Suspension

Areas’’ maps which we publish prior to

lease sales in areas where the deepwater royalty relief program applies.

These maps are based on bathymetric

data from the National Oceanic and

Atmospheric Administration. For

purposes of drawing the map, if the

water depth contour crosses a block, we

include that block in the deeper water

category. We will use the version of that

map that is in effect at the time the

royalty suspension application is

submitted to determine the water depth

of the field.

Applications

Lessees may submit applications for

royalty relief under the provisions of

this interim rule to the MMS Regional

Director, Gulf of Mexico Region. Lessees

may submit applications for:

(1) A PDWL or unit in a field that did

not produce (other than test production)

prior to November 28, 1995; or

(2) A PDWL or unit proposing

development in a supplemental DOCD

approved after November 28, 1995, that

will expand production significantly

beyond the level anticipated in a prior

DOCD.

Because we have not required DOCD’s

to show anticipated production, we

have chosen to define significant

expansion of production as any project

that will result in an increase in

ultimate recovery of resources from the

field and that involves a substantial
27268 Federal Register / Vol. 61, No. 106 / Friday, May 31, 1996 / Rules and Regulations

capital investment (e.g., installation of a

fixed-leg platform, subsea template and

manifold, tension-leg platform, or

multiple well projects).

The DWRRA directs applicants to

provide information required for a

‘‘complete application’’ and directs the

Secretary to define clearly the

information required. This interim rule

requires the submission of several

reports as part of a complete

application. The information required in

the reports includes field geology and

geophysics, project design, field

development and production plan

(including planned time that production

will begin and rates of production),

costs (projected and past, if any), and a

discounted cash flow (DCF) analysis of

the field development and production.

The Gulf of Mexico Regional Office

will make guidelines available to all

lessees. These guidelines contain

detailed instructions on the specific

information and data elements required

for a complete application.

As specified in the interim rule at

§ 203.55(c), the applicant or the

applicant’s authorized representative

must certify that all information

submitted in the application is accurate

and complete. The application must be

accompanied by a report prepared by an

independent certified public accountant

(CPA) expressing an unqualified

opinion on the accuracy of the historical

financial information presented in the

application. The applicant must make

the independent CPA available to us to

respond to questions which may arise

regarding the evaluation of the historical

information. This requirement does not

prevent further review of the applicant’s

records which support the historical

financial information included in the

application.

In developing the information

requirements for a complete application,

we observe that much of the geologic

and economic information to be

provided by an applicant who holds a

non-producing PDWL is, by its very

nature, imprecise (i.e., estimated or

projected). Thus, it is important to set

information requirements that enable us

to make the DWRRA determinations

with reasonable certainty.

To reduce the uncertainty of the

information, the application should be

submitted as late in the development

process as possible, though before

production commences. By waiting

until later in the development process,

activities such as drilling of

development wells and procurement of

facilities will provide more reliable

information about costs and potential

future income.

We note that lessees would prefer to

have a decision made about relief early

in the life of the lease to help in project

planning and in arranging financing.

Lessees with leases on a field that could

be economic with royalty relief want to

know whether and how much relief

they will receive before making

substantial post-discovery investments

on their leases. Thus, there is a trade-off

between our need for reasonably

complete information and the lessee’s

desire for an early decision.

Our decisions on this issue

incorporate ideas developed during

ongoing discussions of possible new

types of regulatory approvals relating to

the development of deep-water oil and

gas leases. A reasonably clear point in

the OCS lease development process

exists when detailed engineering and

design activities necessary for the

development of discovered resources

have been completed, but capital

investment for procurement and

construction has not begun. The lessee

has advanced the engineering, geology,

and geophysics to a degree that more

certainty exists in comparison to the

earlier, exploration stage. Yet, the lessee

has not made major financial

commitments such as procuring

facilities or drilling development wells.

Under the requirements for a

complete application, the lessee must

provide its design of production

facilities needed for field development.

The design of development and

production facilities reflects the

applicant’s belief that the field merits

development and qualifies for royalty

relief. This approach avoids focusing on

discoveries that have not yet been

delineated and making major

investments in the absence of

knowledge about whether and to what

extent the field qualifies for royalty

relief and, if so, how large a royalty

suspension volume we will grant.

A complete application must include

an approved DOCD for a PDWL or unit

or a supplemental DOCD for a PSEP. In

joint applications, at least one lessee of

a lease participating in the application

must have an approved DOCD or an

approved supplemental DOCD. The

requirement for an approved DOCD for

a complete application helps avoid

submission of premature applications,

since a DOCD covers the major system

elements such as the platform and the

development wells. A DOCD is not

normally submitted to us until

development design has progressed to a

fairly final stage.

We considered requiring mandatory

unitization of leases on a field if

necessary to provide for the most

efficient development of the field.

However, in recognition of the

responses to the ANPR in which

virtually all lessees who provided

comments opposed mandatory

unitization, and since we continue to

have the authority to compel the

unitization of operations on OCS leases

on a case-by-case basis, we have elected

not to require the unitization of field

operations as a necessary feature of a

complete application for the suspension

of royalty under the DWRRA.

Rather, we are requiring joint

application procedures. In applying for

royalty relief, all lessees on a field must

submit a combined, joint application

(§ 203.53(b)(3)(i)). If lessees do not want

to share proprietary data with other

lessees on the field, the proprietary

geologic and geophysical data that is

part of the joint application can be

submitted separately and we will

protect its confidentiality

(§ 203.53(b)(3)(ii)). We will not deem the

application complete until we receive

all the required information for each

lease on the field. If the application is

subsequently denied, MMS will not

disclose a lessee’s proprietary data to

other lessees in our explanation of our

determinations.

The approach we have chosen to

pursue for this interim rule represents a

reasonable middle ground that protects

the public interest while still allowing

lessees flexibility of operation. That is,

while a joint application that describes

joint development of the field is

required, lessees may develop their

individual leases independently if they

so choose.

Some lessees may be unwilling to

provide the information necessary for a

complete joint application even if it

means foregoing an opportunity to share

in the royalty suspension volume

assigned to a field. In such cases, we

will grant a good cause exception to the

joint application requirement and will

accept and evaluate an application from

the remaining lessee(s)

(§ 203.53(b)(3)(iii)). The application

must include evidence of efforts to gain

the cooperation of the non-participating

lessee(s). While the noncooperating

lessee(s) forfeits the right to receive a

royalty suspension for the field that is

the subject of the application under

these DWRRA provisions, it may apply

for royalty relief under other provisions.

Lessee(s) on a field may apply only

once for a mandated royalty suspension

volume for that field, except under the

circumstances described below or for a

PSEP (§ 203.53(b)(3)(iv)). The DWRRA

specifically allows lessees to request a

redetermination under certain limited

circumstances, as discussed below.

However, if unlimited applications were
Federal Register / Vol. 61, No. 106 / Friday, May 31, 1996 / Rules and Regulations 27269

permitted, there would be no need for

the DWRRA’s redetermination

provisions. Therefore, we believe it is

consistent with Congressional intent to

allow only one application per field,

except under the redetermination

criteria or when we withdraw a prior

approval of a royalty suspension

volume, as discussed below.

Within 20 working days of the receipt

of an application, we will determine

whether it is complete (§ 203.53(c)(1)(i)).

If the application is complete, we will

notify the applicant and start to evaluate

it. If the application is incomplete, we

will provide the applicant an

explanation of the additional data we

need to make it complete.

The DWRRA provides that if we do

not make our required determinations

within 180 days after we receive a

complete application (or 120 days in the

case of a redetermination), we may

extend the time period for making our

determination or redetermination for 30

days, or for longer than 30 days if agreed

to by the applicant (§ 203.53(c)(1)(ii)).

If we do not complete our required

determinations in the prescribed time

period, the field is granted the

minimum royalty suspension volume

automatically. In the case of a PSEP, the

DWRRA specifies that no royalty is due

on such production for a period of one

year following the start of such

production.

The interim rule specifies that the

180-day time period for our

determination, or 120-day time period

for redeterminations, begins when we

have determined that the application is

complete and so notify the applicant.

We view the evaluation process as

one where we may interact with the

applicant. If, during this process, we

find that data or information in the

application is unclear, inconclusive, or

otherwise cannot be relied upon, we

will notify the applicant to provide such

new data or information as is needed to

make the application complete and

accurate. We will request that the 180-

or 120-day time period be tolled from

the time the applicant receives our

notice until the needed information is

provided. When the applicant supplies

the needed information, we will restart

the time period with the same number

of days remaining for us to make our

determinations as when the time was

tolled. The alternative to tolling the

clock is for us to reject the application

because the data and information does

not adequately support the

determination we must make under the

DWRRA.

Review and Evaluation Procedures

In evaluating applications for deepwater royalty relief, we will make the

following determinations:

• Would the new production be

economic without a royalty suspension;

and

• Is there any royalty suspension

volume that we could grant that would

make the new production economic?

If the answer to the first

determination is that production would

not be economic without relief and the

answer to the second is that there may

be a royalty suspension volume that

would make the new production

economic, we will proceed to a third

determination: what amount of relief

should we grant, i.e., the minimum

royalty suspension volume mandated in

the DWRRA or a volume in excess of

that minimum?

The OCSLA authorizes these

determinations in section 8(a)(3)(C)(ii).

First, the provision reads, ‘‘the Secretary

shall determine * * * whether new

production from such lease or unit

would be economic in the absence of

the relief * * *’’ Second, that same

section mandates that the Secretary

‘‘determine the volume of production

from the lease or unit on which no

royalties would be due in order to make

such production economically viable

* * * .’’ If there is no amount of royalty

relief which would make the new

production economic, then there is no

way the Secretary can calculate the

‘‘volume of production from the lease or

unit on which no royalties would be

due in order to make such production

economically viable * * * .’’ Thus, our

determination of whether there exists a

royalty suspension volume that would

make new production economic is

necessary for the Secretary to proceed to

a determination of a volume of royalty

suspension that would make production

economically viable.

If new production from a field or

project is economic in the absence of

royalty relief, the relief provisions of the

DWRRA do not authorize relief and we

will reject the application. If no amount

of royalty relief would make a field (or

project) economic, we will disapprove

the application. In such a case, the

royalty relief would not induce the

lessee to develop the field or marginal

project.

The DWRRA requires us to determine

whether new production would be

‘‘economic’’ taking into consideration

the risks of deep-water development

and all costs associated with

exploration, development, and

production. However, the term

‘‘economic’’ is not defined in the

DWRRA. For this interim rule, we have

defined ‘‘economic’’ as a project or

group of related projects, such as fieldwide development, having a positive net

present value as calculated with MMSstipulated DCF techniques.

The DWRRA requires us to consider

all costs of exploration, development,

and production in determining whether

a field is economic in the absence of

royalty relief. In making this

determination, we will include only

those sunk costs incurred after the date

of field discovery because of the

difficulties in attributing to a particular

field those sunk costs incurred before a

discovery.

Similarly, we will not include sunk

costs when we determine whether a

field can be made economic with

royalty relief or when we determine the

amount of royalty suspension volume

needed to make the new production

economic. First, only prospective costs

are relevant to determining the royalty

suspension volume needed to make the

new production economic. Second, the

DWRRA does not state that ‘‘all costs’’

must be considered in determining the

appropriate suspension volume.

This treatment of sunk costs applies

only to fields that did not produce,

other than test production, prior to the

date the application for royalty

suspension is submitted. We will not

count any sunk costs where production

commenced prior to the date the

application is submitted or when the

application is proposing a significant

expansion of production. According to

economic theory, such costs generally

are not relevant to decisions about

whether to continue producing from a

developed field. Since the intent of the

DWRRA is to bring new fields into

production-not to ensure a rate of return

on developed fields-we will not count

sunk costs in such cases.

The guidelines provide more detailed

information on costs, prices, and

discount rates. In general, the applicant

provides the cost data we use to make

our determinations. Based on our

experience in administering NRS

royalty relief, we will not include some

types of costs in the analysis, as

specified in § 203.55(b). We will verify

the costs reported and, where sunk costs

are important, this verification may

include an audit of those costs. The

costs and the underlying geology and

design data are given in ranges or with

probability distributions, reflecting the

uncertainties and risks of the field

development.

We will provide applicants with the

assumptions for oil and gas prices to use

in the DCF analyses. We will develop

future price assumptions after
27270 Federal Register / Vol. 61, No. 106 / Friday, May 31, 1996 / Rules and Regulations

considering long-term projections of oil

and gas prices by major forecasters, such

as (but not limited to) the Energy

Information Administration, Data

Resources Incorporated, and Wharton

Econometrics. We will update these

price forecasts periodically. These

assumptions provide reasonable

forecasts that all applicants can employ.

Applicants may adjust prices for the

expected quality of the resource,

documenting these adjustments as

discussed in our guidelines.

We will also specify a range of

discount rates from which applicants

will choose a particular rate. The reason

for allowing a choice of discount rates

is that projects differ in their risk

characteristics, and further, operators

might have different risk preferences

reflected in their target rates of return.

Our guidelines will set the range of

discount rates for use in the DCF

analyses. We may change the range

periodically.

In determining the volume

suspension needed to make the field

economically viable, we will employ a

similar DCF model and the same price

and discount assumptions used to show

whether royalty relief can make the field

economic. We will also input the

geological assessments, engineering

designs, production scenarios and cost

components included in the

application, subject to our review and

verification of their accuracy and

efficiency. In cases where we find that

assumptions other than those provided

by the applicant are more appropriate,

we reserve the right to make all

necessary changes in the set of inputs.

In general, we have structured our

determinations following the principle

that the DWRRA aimed to give

substantial, but not excessive, incentive

to develop marginal fields. In this

manner, we seek to avoid the errors of

rejecting deserving applications or

giving large amounts of volume

suspension when they are not needed.

Note that being granted a royalty

suspension volume on production from

a PDWL under the regulations

established by this rulemaking does not

preclude a lessee from obtaining further

relief under the pre-DWRRA provisions

of the OCSLA, the expanded OCSLA

royalty relief provisions created by the

DWRRA, or under the significant

expansion of production portion of the

DWRRA.

Also, as noted above a lessee may

apply only once for a royalty suspension

volume for a given field under the

DWRRA provisions, except as provided

below.

Redeterminations

The DWRRA provides that an

applicant may request a redetermination

of the Secretary’s findings prior to the

start of new production if a significant

change occurs in the factors upon which

we based the original determination. We

believe that the Congress established

this requirement, in part, to place

reasonable limits on the number and

frequency of redetermination requests

so the Secretary would not need

significant new staff resources to

administer the program.

Accordingly, we will accept an

application for a redetermination only

when:

(1) Changes in resource information

(e.g., gross resources, quality, flow rates)

are of sufficient magnitude that, had our

evaluation of the original application

included the new data, the results of our

determinations would have been

materially different. The new resource

information must result from new

exploration activity such as drilling a

new well or acquiring new 3–D seismic

data that did not exist at the time of the

original application. A reinterpretation

of existing data does not qualify as a

significant change in resource

information; or

(2) Average annual prices of oil and

gas have fallen by 25 percent since the

previous application. These averages are

determined by:

(A) using daily closing prices for light

sweet crude oil and natural gas on the

New York Mercantile Exchange

(NYMEX) over 12-month periods; and

(B) weighting the annual average

prices by the volumes of oil and gas (in

barrels of oil equivalent) identified in

the most likely development and

production scenario (required under

§ 203.55 and described in the

guidelines) in the previous application

for royalty relief. (See § 203.53(d)(1)(ii)

for details.)

We are establishing this condition to

avoid having economic projects appear

uneconomic, and therefore qualify for a

royalty suspension volume, due to what

may only be a brief temporary downturn

in prices. While smaller price changes

can affect the economic viability of

development, larger, sustained changes

in underlying prices must occur before

we would change the price scenarios

used in evaluating applications. Further,

a drop in oil prices should not trigger a

potential redetermination for a project

proposing to develop a 100 percent gas

field or vice versa. Therefore, the

weighted average price change is

required; or

(3) Prior to starting construction of

your project, estimated project

development costs amount to more than

120 percent of the eligible development

costs included for the most likely

development scenario as set forth in the

previous application.

Applicants requesting a

redetermination must include a new

complete application in accordance

with the requirements of § 203.53(b) and

§ 203.55. We will evaluate the request to

see if the applicant is eligible for a

redetermination. If so, we will proceed

to evaluate the application.

As with an original application for a

royalty suspension, we have 20 working

days to determine whether an

application for a redetermination is

complete. If the application is complete,

we must evaluate the application within

120 days. We can extend this period for

30 days, or longer if agreed to by the

applicant(s).

Withdrawal of Approvals and Changes

in Material Fact

If we find that an applicant provided

false historical information or

intentionally inaccurate data that was

material to us in granting royalty relief

under this section, we will rescind our

approval of that relief as of the date of

the approval. The applicant must pay

royalties and late payment interest

determined under 30 U.S.C. 1721 and

30 CFR 218.54 on all volumes of

production on which royalty was not

paid. The lessee also may be subject to

penalties under other provisions of law.

We further reserve the right to

withdraw our approval of a royalty

suspension if a change in material fact

occurs that is significant enough to

invalidate the basis on which we

originally evaluated and approved the

application. Material changes that will

result in a withdrawal of an approved

royalty suspension volume include:

(1) The lessee changes the type of

development system proposed in the

approved application. For example, the

development proposal changes from a

stand-alone platform, as proposed in the

approved application, to a much less

expensive subsea template and tie-back.

(2) Construction of the production

system described in the application

does not commence within 2 years of

the date of application approval,

notwithstanding any suspensions of

operations.

(3) Actual development costs incurred

prior to the commencement of

production, other than test production,

amount to less than 80 percent of the

estimated development costs included

for the most likely development and

production scenario presented in the

approved application.
Federal Register / Vol. 61, No. 106 / Friday, May 31, 1996 / Rules and Regulations 27271

We will use the pre-production report

(§ 203.53(c)(4)) to determine whether

the actual capital costs meet this

threshold. As an incentive for efficient

investment and to provide greater

certainty at the time of the application,

a portion of the originally granted

royalty relief can be automatically

retained. If the applicant informs us of

the development cost discrepancy in the

pre-production report, the applicant

will be entitled to 50 percent of the

approved royalty suspension volume

with no further action required (see

§ 203.53(e)(3)(i)). If we discover the

development cost discrepancy after

production, other than test production,

has started, approval of the royalty

suspension volume will be retroactively

withdrawn (see § 203.53(e)(3)(iii)).

However, if the royalty suspension

volume resulted from a redetermination

based on a change in capital costs, as

discussed above, we will withdraw our

approval of the application if actual

development costs are less than 90

percent of the estimated development

costs included in the most likely

development and production scenario

in the approved application, and the

lessee will not be permitted to retain

any of the approved royalty suspension

volume (see § 203.53(e)(3)(ii)).

We considered other factors as

grounds for withdrawal of our approval

of an application, but we concluded that

the factors discussed above were

sufficient to protect the public interest.

The applicant may initiate a new

application for a suspension volume

when its previously approved royalty

suspension volume is withdrawn for

reasons other than the submission of

false information or intentionally

inaccurate data.

The material changes triggering a

potential withdrawal of approval of the

royalty suspension volume are at least

partially at the discretion of the lessee(s)

and the potential for a subsequent

withdrawal of our approval for a royalty

suspension should be considered by

applicants when deciding to make

changes of this nature.

Allocation Rules

Fields in deep water may consist of

one or more leases, including leases

issued as a result of sales held before

and after November 28, 1995, and leases

in different water depths. Therefore, to

make royalty relief consistent with the

DWRRA, we need to specify how the

royalty suspension volume applies in

many different circumstances.

Accordingly, the following cases

illustrate how the rule applies in

determining eligibility for, and the

volume of, royalty suspensions. (All

cases assume that all eligible leases on

a field participate in the joint

application for a royalty suspension

volume; the term ‘‘eligible leases’’ is

defined in the interim rule for deepwater royalty relief on leases issued

from sales after November 28, 1995 (61

FR 12022, 30 CFR 260.110)).

Case 1. If a field consists of a single PDWL

and the application is approved, no royalty

payment is required on production from the

lease until that production equals the royalty

suspension volume granted.

Case 2. If a field consists of more than one

PDWL and the application is approved,

payment of royalties on production from the

PDWL’s is suspended until their cumulative

production equals the suspension volume

granted. The royalty suspension volume for

each lease equals each lease’s actual

production (or production allocated under an

approved unit agreement) until cumulative

production from the field equals the field’s

royalty suspension volume.

Case 3. If a PDWL or an eligible lease is

added to a field that has been granted a

royalty suspension volume under the

regulation established by this rulemaking, the

field’s royalty suspension volume will not

change. The additional lease may receive a

royalty suspension volume only to the extent

of its production before the cumulative

production from the field equals the

approved royalty suspension volume.

In this case, the added PDWL will not be

required to submit the full application

required of the original applicants. A full

application is not necessary because we have

already evaluated the field and set an

appropriate royalty suspension volume. We

see no need to reevaluate that determination.

Accordingly, the operator of the PDWL can

apply for relief using an abbreviated

application available at the Gulf of Mexico

OCS Regional Office.

Case 4. If the PDWL is part of a field that

has a royalty suspension volume for eligible

leases under § 260.110, the lessee(s) may

apply for relief. If the application meets the

economic and economic viability tests, all of

the leases can share the royalty suspension

volume until total cumulative production

from the field attains the royalty suspension

volume that is the greater of the volume

established for the eligible leases under

§ 260.110 or the volume determined pursuant

to the regulation established by this

rulemaking.

Case 5. A lease may receive more than one

royalty suspension volume. An application

may be made for relief for a lease under the

regulations established by this rulemaking for

each field that includes the lease. Each field

will receive a separate royalty suspension

volume if it meets the evaluation criteria

described below. An application also may be

made for relief for a project that would result

in a significant expansion of production,

even if we have already granted a royalty

suspension volume to the field that

encompasses that project. For a PSEP, this is

how the rule applies:

Case 6. If a PDWL is the only lease on the

project and the application based on a

significant expansion of production is

approved, no royalty payment is due on the

incremental production from the project until

that production equals the royalty

suspension volume granted.

Case 7. If the expansion of production

project includes more than one lease and the

application is approved, payment of royalties

on incremental production from the project

is suspended until the lessees’ cumulative

incremental production from the project

equals the suspension volume granted. The

royalty suspension volume for each lease

equals each lease’s actual production from

the project until cumulative production

equals the project’s royalty suspension

volume.

In all cases, the addition of a lease to a

field that has an established royalty

suspension volume will not change the

field’s royalty suspension volume, even if the

added lease is in deeper water.

Other Issues

Appeals—Our determinations and

redeterminations under 43 U.S.C.

1337(a)(3)(C) are final agency actions

which are judicially reviewable under

section 10(a) of the Administrative

Procedure Act (5 U.S.C. 702). Requests

for judicial review of a determination or

redetermination under 43 U.S.C.

1337(a)(3)(C) must be filed within 30

days of our decision.

Gas-to-oil conversion factor—The

royalty suspension volumes are

measured in millions of barrels of oil

equivalent. For the purposes of this rule,

5.62 thousand cubic feet of natural gas

equal one barrel of oil equivalent, as

measured at 15.025 pounds per square

inch (psi) pressure, 60 degrees

Fahrenheit, and fully saturated

(§ 203.53(g)(5)). This is the conversion

factor traditionally used in the Gulf of

Mexico and is the same factor specified

in § 260.110(d)(11) for calculating

royalty suspension volumes for new

leases.

Non-royalty bearing production—

Under this rule, any lease-use

production that otherwise is not subject

to royalty does not count toward the

royalty suspension volume.

Price escalation clause—In

accordance with section 302, in any

calendar year during which the

arithmetic average of the daily closing

prices on the NYMEX for light sweet

crude oil exceeds $28.00 per barrel,

adjusted for inflation as described

below, any royalty relief we grant under

the provisions of this rule for DWLP’s

and PSEP’s is suspended and any

production of oil is subject to royalties

at the lease stipulated royalty rate.

However, this production counts as part

of the established royalty suspension

volume. By January 31 of the year

following the calendar year in which the

price exceeded $28.00 per barrel, the

lessee must pay the royalty due plus
27272 Federal Register / Vol. 61, No. 106 / Friday, May 31, 1996 / Rules and Regulations

interest in accordance with 30 U.S.C

1721 and 30 CFR 218.54, on any volume

of oil produced during the previous year

on which no royalties were paid.

In any year following a calendar year

in which the arithmetic average of the

daily closing prices on the NYMEX for

light sweet crude oil exceeded $28.00

per barrel, as adjusted for inflation, the

lessee must pay royalties on all the oil

it produces that year. If, after the end of

the year, the arithmetic average of the

daily closing prices on the NYMEX for

light sweet crude oil for that year was

$28.00 per barrel or less, as adjusted for

inflation, the lessee is entitled to a

refund or credit, with interest, of

royalties paid that year on any royalty

suspension volume for oil production.

Regulations for receiving refunds or

credits are at 30 CFR part 230.

This rule similarly applies to natural

gas. In any calendar year during which

the arithmetic average of the daily

closing prices on the NYMEX for natural

gas exceeds $3.50 per million British

thermal units (Btu’s), adjusted for

inflation as described below, any royalty

relief we grant under the provisions of

this rule for DWLP’s and PSEP’s is

suspended and any production of gas is

subject to royalties at the lease

stipulated royalty rate. However, this

production counts as part of the

established royalty suspension volume.

By January 31 of the year following the

calendar year in which the price

exceeded $3.50 per million Btu’s, the

lessee must pay the royalty due plus

interest in accordance with 30 U.S.C

1721 and 30 CFR 218.54, on any volume

of gas produced during the previous

year on which no royalties were paid.

In any year following a calendar year

in which the arithmetic average of the

daily closing prices on the NYMEX for

natural gas exceeded $3.50 per million

Btu’s, as adjusted for inflation, the

lessee must pay royalties on all the gas

it produces that year. If, after the end of

the year, the arithmetic average of the

daily closing prices on the NYMEX for

natural gas for that year was $3.50 per

million Btu’s or less, as adjusted for

inflation, the lessee is entitled to a

refund or credit, with interest, of

royalties paid that year on any royalty

suspension volume for gas production.

Regulations for receiving refunds or

credits are at 30 CFR part 230.

To adjust for inflation, change the

prices referred to above (i.e., $28.00 per

barrel for light sweet crude and $3.50

per million Btu’s for natural gas) during

each calendar year after 1994 by the

percentage, if any, by which the implicit

price deflator for the gross domestic

product changed during the preceding

calendar year.

The particulars of this provision of

the DWRRA are included at § 203.53(h)

(6)–(8) of this rulemaking.

Termination of royalty suspension

volumes—A royalty suspension will

continue until the end of the month in

which the cumulative production from

the applicable leases in the field or

project reaches the royalty suspension

volume for the field or project. We will

provide monthly production data to all

lessees in the field or project. However,

this data may not become available until

shortly after production exceeds the

royalty suspension volume. In such

cases, royalties still will be due on the

last day of the second month following

the month in which cumulative

production from the field or project

reaches the royalty suspension volume.

Any royalties paid late will be subject

to interest pursuant to 30 CFR 218.54.

VI. Recovery of Costs

In accordance with Federal policy and

statute, we will charge lessees applying

for royalty relief under the provisions of

the regulation promulgated by this

rulemaking an amount which recovers

our cost of processing their applications.

The Administrative Procedure Act (31

U.S.C. 9701) and Office of Management

and Budget Circular A–25 require that

agencies recover their costs when they

provide services that confer special

benefits or privileges to identifiable

non-Federal recipients. Processing of

applications for royalty relief clearly

falls within this mandate.

Furthermore, the collection of such

fees is specifically authorized by the

Omnibus Appropriations Bill (Pub. L.

104–134, 110 Stat. 1321, April 26,

1996). The statute provides: ‘‘That

beginning in fiscal year 1996 and

thereafter, fees for royalty rate relief

applications shall be established (and

revised as needed) in Notices to Lessees,

* * * for the costs of administering the

royalty rate relief authorized by 43

U.S.C. 1337(a)(3).’’

We estimate that our costs for

processing NRS applications will range

from $8,500 (continuation of

production) to $22,500 (project

involving capital expansion). For

applications for deep-water royalty

relief, we estimate that our costs will

range from $27,500 to $50,000

depending on the number of leases

involved and the complexity of the

proposed development project. For

some applications, we may find it

necessary to audit the financial data

submitted to make an adequate

determination on the economics of the

proposed development. We estimate

that it will cost us up to $40,000 to

conduct such an audit.

We will issue a Notice to Lessees

(NTL) that will provide more detailed

information on the amounts of royalty

relief application processing costs and

when and how applicants may make

payments to us. We will revise the NTL

periodically to reflect our cost

experience and to provide other

information helpful or necessary for the

administration of this program.

VII. Administrative Matters

Executive Order (E.O.) 12866

The interim rule is significant due to

novel policy issues arising out of legal

mandates, and the Office of

Management and Budget (OMB) has

reviewed this rule. We will make a copy

of this determination available on

request.

We focused on impacts on royalty

revenues of regulatory alternatives in

determining the possible economic

effects of implementing section 302 of

the DWRRA. We assumed that there

would not be significant impacts on

labor and capital because, given current

constraints on the availability of deepwater drilling rigs, companies active in

these areas would make similar

alternative investments in the absence

of the DWRRA over the near term.

We analyzed two alternatives for

implementing section 302. The

approach in this interim rule (MMS

approach) gives a single royalty

suspension volume for each qualifying

field. The alternative approach gives

each individual lease or unit separate

royalty suspension volumes, subject to

the minimum volumes specified in the

DWRRA.

Because the DWRRA instructs us to

grant royalty relief only in situations

that are uneconomic at the leasestipulated royalty rate, the revenue

effects are the additional royalties that

may be collected from fields that would

otherwise not be developed until a later

time, if at all. We estimated these effects

by extrapolating to all known deepwater fields the results of detailed

analyses of 30 fields in the relevant

water depths. The MMS approach

generates up to an estimated $45 million

per year in royalty revenue in peak

years. The alternative approach

frequently results in no royalty

payments, and when such payments do

occur, they would be less than the

royalties received under the MMS

approach. Thus, in both cases, the

economic effects are less than $100

million annually.

We chose the approach embodied in

this interim rule because:

• The DWRRA’s primary author stated

that he intended the DWRRA to
Federal Register / Vol. 61, No. 106 / Friday, May 31, 1996 / Rules and Regulations 27273

encourage production from new fields

without providing too much relief;

• The MMS approach provides a

substantial incentive for developing

marginal fields in deep water while still

ensuring a reasonable return to the

Treasury;

• The minimum suspension volumes

specified in the DWRRA were derived

from an analysis of fields, not

individual leases; and

• This rule needs to be consistent

with the rules for royalty suspensions

on deep-water tracts leased after

November 28, 1995, in the same parts of

the Gulf of Mexico so that all deepwater OCS lessees receive equitable

treatment.

Regulatory Flexibility Act

This rule will not have a significant

effect on small entities.

This rule establishes the terms and

conditions for granting royalty relief

under the provisions section 8(a)(3)(A)

of the OCSLA and royalty suspension

volumes under the DWRRA for certain

deep-water OCS Gulf of Mexico leases

that were issued as the result of a lease

sale held prior to November 28, 1995.

The estimates of development costs

for fields in the deep water of the Gulf

of Mexico range from over $10 million

to about $2 billion. We, therefore,

concluded that, in general, the entities

that engage in offshore oil and gas

development and production activities

are not small due to the technical and

financial resources and the experience

needed to safely conduct such activities.

Small entities who are likely to work

in the deep waters of the OCS are

primarily contractors who provide

services such as catering or custodial

services for manned facilities. This rule

will impact these entities only to the

degree that the royalty relief provided

results in the drilling of additional wells

and installation of additional manned

facilities.

Administrative Procedure Act

We have determined, in accordance

with 5 U.S.C. 553(b)(3)(B) of the

Administrative Procedure Act, that a

notice of proposed rulemaking is not

required and is impracticable in the

issuance of this rule. We invite

comments on this interim rule so

changes can be made in the future, if

warranted.

Paperwork Reduction Act

The MMS has submitted the

information collection requirements in

30 CFR 203 to the Office of Management

and Budget (OMB) with a request for

emergency processing. We have stated

that the time period for OMB approval

should coincide with the effective date

of this Interim Rule. The information

collection in this rule has been

approved on an emergency basis

through August 31, 1996, under OMB

control number 1010–0071. However,

we still will conduct a full review and

comment process for this collection of

information. The new title, ‘‘30 CFR

203, Relief or Reduction in Royalty

Rates,’’ is consistent with that of the

interim final rule for Part 203.

Send comments regarding the burden

or any other aspect of the collection of

information contained in this part,

including suggestions for reducing the

burden, to the Information Collection

Clearance Officer, Minerals

Management Service, Mail Stop 2300,

381 Elden Street, Herndon, VA 22070–

4817 and to the Office of Information

and Regulatory Affairs, Office of

Management and Budget, Attn: Desk

Officer for the Department of the

Interior (OMB control number 1010–

0071), Washington, DC 20503.

The Paperwork Reduction Act of 1995

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.

Respondents to this collection of

information are Federal oil and gas

lessees. The frequency of response is on

an occasion basis. We expect the

number of responses (applications) for

the remainder of this fiscal year to be

relatively small. The number will peak

during fiscal year 1997 and decline

thereafter. The following chart

represents an average of the anticipated

number of annual applications over a

three year period and the associated

reporting burdens. The burden estimates

include the time for reviewing

instructions, searching existing data

sources, gathering and maintaining the

data needed, and completing and

reviewing the collection of information.

OCSLA

Type of application Responses

per year

Hours per

response

Hours per

year

Leases with inadequate revenues to sustain continued production ........................................................ 4 300 1,200

Leases proposing an expansion of production that would be uneconomic absent relief ....................... 7 800 5,600

Total annual burden ...................................................................................................................... .................... .................... 6,800

DWRRA

Type of Application Responses

per year

Hours per

response

Hours per

year

DWRRA lease on a field that did not produce prior to 11/28/95 ............................................................. 23 1,200 27,600

DWRRA leases proposing a significant expansion of production ........................................................... 7 800 5,600

Redetermination ....................................................................................................................................... 6 800 4,800

Short Form Applications ........................................................................................................................... 7 40 280

Total annual burden ...................................................................................................................... .................... .................... 38,280

In addition to the hour burden

outlined above, there are two other cost

burdens to the respondents. (1) We will

charge lessees (respondents) applying

for royalty relief an amount which

covers the cost of processing their

applications. This is discussed above in

Section VI. Recovery of Costs. (2) A

respondent’s application or preproduction report must be accompanied

by a report prepared by an independent

certified public accountant as described

in section 203.55(c) of the rule.
27274 Federal Register / Vol. 61, No. 106 / Friday, May 31, 1996 / Rules and Regulations

Takings Implication Assessment

The Department of the Interior

certifies that this rule does not represent

a governmental action capable of

interference with constitutionally

protected property rights. A Takings

Implication Assessment prepared

pursuant to E.O. 12630, Government

Action and Interference with

Constitutionally Protected Property

Rights, is not required.

E.O. 12988

The Department has certified to the

OMB that this regulation meets the

applicable standards provided in

section 3(b)(2) of E.O. 12988.

National Environmental Policy Act

We examined the interim rule and

have determined that it does not

constitute a major Federal action

significantly affecting the quality of the

human environment pursuant to section

102(2)(C) of the National Environmental

Policy Act of 1969 (42 U.S.C. 4332).

Unfunded Mandate Reform Act of 1995

This rule does not contain any

unfunded mandates to State, local, or

tribal governments or the private sector.

List of Subjects in 30 CFR Part 203

Continental shelf, Government

contracts, Indians-lands, Minerals

royalties, Oil and gas exploration,

Public lands—mineral resources, Sulfur.

Dated: May 20, 1996.

Bob Armstrong,

Assistant Secretary, Land and Minerals

Management.

For the reasons in the preamble, the

Minerals Management Service (MMS) is

amending 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; 43 U.S.C. 1301, et seq.; 43 U.S.C. 1331

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

2. Subpart A is added to read as

follows:

Subpart A—General Provisions

§ 203.1 Authority for information

collection.

(a) The Office of Management and

Budget (OMB) approved the information

collection requirements in part 203

under 44 U.S.C. 3501 et seq. and

assigned OMB control number 1010–

0071. The MMS uses the information to

determine whether granting a royalty

relief request will result in the

production of resources that would not

be produced without such relief. The

application for royalty relief must

contain sufficient financial, economic,

reservoir, geologic and geophysical,

production, and engineering data and

information to determine whether relief

should be granted in accordance with

applicable law. the application also

must contain sufficient data and

information to determine whether the

requested relief will result in an

ultimate increase in resource recovery

and provide for reasonable returns on

project investments. The applicant’s

requirement to respond is related only

to the request to obtain royalty relief.

The applicant has no obligation to make

this request.

(b) An agency may not conduct or

sponsor, and you are not required to

respond to, a collection of information

unless it displays a currently valid OMB

control number.

(c) Send comments regarding the

burden of this information collection or

any other aspect of the collection of

information under provisions of this

part, including suggestions for reducing

the burden, to the Information

Collection Clearance Officer; Minerals

Management Service, Mail Stop 2300,

381 Elden Street; Herndon, Virginia

20170–4817 and the Office of

Management and Budget; Office of

Information and Regulatory Affairs,

Attn: Desk Officer for the Department of

the Interior (1010–0071); Washington,

DC 20503.

(d) The MMS will protect information

considered confidential or proprietary

under applicable law and under

regulations at § 203.53(b)(ii) and part

250 of this chapter.

3. Subpart B is revised to read as

follows:

Subpart B—OCS Oil, Gas, and Sulfur,

General

Sec.

203.50 Definitions.

203.51 What is MMS’s authority to grant

royalty relief?

203.52 Net revenue share royalty relief.

203.53 Royalty relief for certain deep-water

leases in the Gulf of Mexico.

203.54 (Reserved)

203.55 What information is required for the

net revenue share royalty relief and

deep-water royalty relief application

supplemental reports?

203.56 Recovery of application processing

costs.

Subpart B—OCS Oil, Gas, and Sulfur,

General

§ 203.50 Definitions.

Terms used in this part have the

following meaning:

Field means an area consisting of a

single reservoir or multiple reservoirs

all grouped on, or related to, the same

general geological structural feature

and/or stratigraphic trapping condition.

There may be two or more reservoirs in

a field that are separated vertically by

intervening impervious strata, or

laterally by local geologic barriers, or

both.

Pre-enactment deep-water lease

(PDWL) means an Outer Continental

Shelf (OCS) lease issued as a result of

a lease sale held before November 28,

1995. The lease must be in a water

depth of at least 200 meters and in the

Gulf of Mexico west of 87 degrees, 30

minutes West longitude.

Project to significantly expand

production (PSEP) means a project

proposed in an approved Supplemental

Development Operations Coordination

Document (DOCD) that will result in an

increase in ultimate recovery of

resources from the field and that

involves a substantial capital

investment (e.g., the addition of a fixedleg platform, subsea template and

manifold, tension-leg platform, multiple

well projects). The project must be on a

PDWL.

Sunk costs means costs (as specified

in § 203.55) of exploration,

development, and production incurred

after the date of first discovery on the

field and prior to the date of application

for royalty relief. Sunk costs also

include the costs of the discovery well

qualified as producible under 30 CFR

250.11.

§ 203.51 What is MMS’s authority to grant

royalty relief?

Under the OCS Lands Act, 43 U.S.C.

1337, as amended by the OCS Deep

Water Royalty Relief Act, Public Law

104–58, MMS may grant three types of

royalty relief listed in this section.

(a) Under 43 U.S.C. 1337(a)(3)(A),

MMS may reduce, suspend, or eliminate

the royalty specified for any producing

OCS lease to promote increased

production. If your OCS lease has

inadequate revenues to sustain

production or if you are proposing a

project to expand production that would

be uneconomic without royalty relief,

MMS may grant royalty relief as

specified in these regulations at § 203.52

(Net Revenue Share Royalty Relief).

(b) Under 43 U.S.C. 1337(a)(3)(B),

MMS may grant royalty reductions or

suspensions to promote development,
Federal Register / Vol. 61, No. 106 / Friday, May 31, 1996 / Rules and Regulations 27275

increase production, or encourage

production of marginal resources on

producing or non-producing leases in

the Gulf of Mexico, west of 87 degrees,

30 minutes West longitude. Section

203.54 is reserved for the regulations to

implement this provision.

(c) Under 43 U.S.C. 1337(a)(3)(C), if

your PDWL is on a field that did not

produce before November 28, 1995, or if

you have a PDWL where you propose a

PSEP, MMS may suspend royalties for

volumes of new production which

would be uneconomic without royalty

relief as specified in these regulations in

§ 203.53 (Royalty relief for certain deepwater leases in the Gulf of Mexico).

§ 203.52 Net revenue share royalty relief.

(a) How do I apply for net revenue

share (NRS) royalty relief?

This section explains how to obtain

royalty relief under 43 U.S.C.

1337(a)(3)(A) if your lease has

inadequate revenues to sustain

production or if you are proposing a

project to expand production that would

be uneconomic without royalty relief.

To apply for relief, submit a complete

application to the appropriate MMS

Regional Director in accordance with

this section and the applicable

guidelines in § 203.52(b) and § 203.55.

An application fee in accordance with

§ 203.56 must accompany the

application.

(b) What do I need to include in my

application?

(1) A complete application for royalty

relief must include an original and two

copies of:

(i) Administrative Information and

Relief Justification, and

(ii) Net Revenue Share Economic

Viability Report.

(2) If you are proposing a project to

expand production that would be

uneconomic without royalty relief, your

application must also include two

copies (one set of digital information) of:

(i) Geologic and Geophysical Report;

(ii) Production Report; and

(iii) Engineering Report.

(3) Section 203.55 describes the

reports required for the complete

application. The appropriate regional

office will provide specific guidance on

the format for the required reports.

(c) What are the NRS royalty relief

approval criteria?

(1) MMS may grant your request for

royalty relief only if it concludes that

royalty relief will increase the ultimate

recovery of hydrocarbons by extending

lease production for at least one year.

However, if you are proposing a project

to expand production, MMS will

approve your request for royalty relief

only if the proposed project would be

uneconomic without royalty relief.

(2) If you have a lease with inadequate

revenues to sustain production, MMS

may grant your request for royalty relief

only if it concludes that:

(i) royalties paid to MMS over the

most recent 12-month period exceed 75

percent of net revenues; and

(ii) royalties are projected to take an

increasing share of net revenues over

the next 12 months.

(d) What royalty relief will MMS

grant?

(1) Except as provided in paragraph

(d)(2)of this section, if you meet the

royalty relief criteria of this section,

MMS may offer to modify the royalty

terms of your lease to a NRS. The

percentage of the net revenue due to

MMS will be established in the MMS

NRS guidelines available in the

appropriate Regional Office.

(2) If you are proposing a project to

expand production but no amount of

royalty relief would make the project

economic, MMS will deny the request

for royalty relief.

§ 203.53 Royalty relief for certain deepwater leases in the Gulf of Mexico.

(a) Who may apply for deep-water

royalty relief?

This section explains how to obtain

royalty relief under 43 U.S.C.

1337(a)(3)(C). You may apply for royalty

relief if you are a lessee of a PDWL or

a unit that contains one or more

PDWL’s, subject to the limitation in

paragraph (b)(3) of this section. You

may apply for relief if:

(1) your lease or unit is part of a field

from which no royalties were due on

production, other than test production,

prior to November 28, 1995; or

(2) you are proposing a PSEP.

(b) How do I apply for deep-water

royalty relief?

(1) You must submit a complete

application to the MMS Regional

Director of the Gulf of Mexico OCS

Region. An application fee in

accordance with § 203.56 must

accompany the application.

(2) A complete application includes

an original and two copies (one set of

digital information) of:

(i) Administrative Information and

Relief Justification;

(ii) Deep-Water Royalty Relief

Economic Viability Report;

(iii) Deep-Water Royalty Relief Cost

Report;

(iv) Geologic and Geophysical Report;

(v) Production Report; and

(vi) Engineering Report.

Section 203.55 describes what these

reports must include. The Gulf of

Mexico Regional Office will provide

specific guidance on the format for the

required reports.

(3) For a royalty suspension on

production from fields from which no

royalties were due on production, other

than test production, before November

28, 1995:

(i) Except as provided in paragraph

(b)(3)(iii) of this section, MMS will

accept only one joint application for all

leases that are part of the field on the

date of application. The Regional

Director maintains a list of all leases in

each discovered field.

(ii) If a lessee does not want to share

proprietary data with other lessees on

the field, that lessee may submit

separately to MMS the proprietary

geological or geophysical data that is a

necessary part of the joint application.

The application is not complete until

MMS receives all the required

information for each lease on the field.

In explaining its assumptions and

reasons for its determinations under this

section, MMS will not disclose

proprietary data.

(iii) MMS will waive the joint

application requirement if the

applicant(s) shows good cause for the

waiver. The applicant also must

demonstrate that it made a good faith

effort to obtain the participation of all

lessees in the field. A lease that is part

of the field on the date of application

but that is not included in the

application because its lessee(s) fails or

refuses to participate is not eligible for

the royalty relief for the field that is the

subject of the application. However, that

lessee still may apply for other royalty

relief under this section.

(iv) With the exceptions listed below,

the lessees on a field may submit only

one complete application for royalty

relief during the life of the field.

However, lessees may submit another

application if:

(A) They are eligible to apply for a

redetermination under § 203.53(d)(1);

(B) MMS has withdrawn approval of

a previously granted royalty suspension

under § 203.53(e);

(C) they apply for royalty relief for a

PSEP; or

(D) they withdraw the application

before MMS deems it complete.

(c) How will MMS evaluate an

application?

(1)(i) MMS will determine within 20

working days if your application for

royalty relief is complete. If your

application is incomplete, MMS will

provide you with an explanation of

what it needs to become complete. If

you withdraw your application after

MMS has deemed it complete, you may

only reapply under the redetermination

provision of § 203.53(d).

(ii) When MMS determines that your

application is complete, MMS will
27276 Federal Register / Vol. 61, No. 106 / Friday, May 31, 1996 / Rules and Regulations

evaluate the application within 180

days. MMS may extend the 180-day

evaluation period for an additional 30

days, if necessary, to complete the

evaluation. If you agree, MMS also may

extend the 180-day period for more than

30 days.

(iii) If MMS must audit sunk costs to

evaluate your application, MMS may

request that the 180-day evaluation

period be tolled from the time you

receive notice from MMS until you

provide the records necessary to

conduct the audit.

(iv) If MMS determines during the

evaluation period that it cannot evaluate

your application because:

(A) vital information is missing;

(B) the data and information provided

in support of the application are

inconclusive; or

(C) of any other valid reason;

MMS may request that the 180-day

evaluation period be tolled from the time you

receive notice from MMS until you provide

needed data, explanations, or revisions.

(2)(i) If your application is for a

suspension of royalties on production

from a field from which no royalties

were due on production, other than test

production, before November 28, 1995,

MMS will determine if development of

the field is economic without royalty

relief. MMS will include your sunk

costs in making this determination. If

MMS determines that development of

the field would be economic without

relief, MMS will deny your request for

a royalty suspension.

(ii) For fields that did produce, other

than test production, before the date of

application, MMS will not include your

sunk costs when it determines if

development of the field is economic

without royalty relief. If MMS

determines that development of the

field would be economic without relief,

MMS will deny your request for a

royalty suspension.

(iii) If MMS determines for a field

subject to either paragraph (c)(2) (i) or

(ii) of this section that development of

the field would not be economic

without a royalty suspension, and that

a royalty suspension could make the

project economic, MMS will determine

the size of the royalty suspension

volume necessary to make the field

economically viable. MMS will

determine your royalty suspension

volume subject to the minimum royalty

suspension volumes specified in

paragraph (h)(1)(i) of this section. MMS

will not include sunk costs when it

makes this determination.

(iv) If no amount of royalty

suspension would make the field

economic, MMS will deny your request

for royalty relief.

(3)(i) If your application for royalty

relief is for a PSEP, MMS will determine

if the proposed project is economic

without royalty relief. If it is economic,

MMS will deny your request for royalty

relief.

(ii) If MMS determines that

development of the project would not be

economic without royalty relief, MMS

will determine the royalty suspension

volume necessary to make the project

economically viable.

(iii) If no amount of royalty

suspension volume would make the

project economic, MMS will deny your

request for royalty relief.

(iv) MMS will not include sunk costs

in evaluating applications for royalty

relief for a PSEP.

(4) If MMS approves your application

for royalty relief, you must submit a preproduction report 60 days before the

planned start of production which is

subject to the royalty suspension

volume, as specified at § 203.55.

(d) When will MMS reconsider its

determination?

(1) You may request a redetermination

of either a denial of an application or

the size of the royalty suspension

volume granted in an approved

application. However, you may request

a redetermination only if you have not

started producing hydrocarbons subject

to the royalty suspension and one of the

following situations occurs:

(i) You have significant new geologic

or geophysical data that did not exist at

the time of the previous application and

that causes you to change your estimates

of gross resource size, quality, or

projected flow rates. Examples of new

data include results from drilling new

wells or obtaining new threedimensional seismic data and

information. Reinterpretation of existing

data is not significant new data. The

change in resource information must be

sufficient to materially affect the results

of the previous determination.

(ii) Prices for oil or gas have decreased

at least 25 percent, determined as

follows:

(A) Calculate the arithmetic average of

daily closing prices for light sweet crude

oil and for natural gas on the New York

Mercantile Exchange (NYMEX) for the

most recent 12 months.

(B) Calculate the weighted average

prices for oil and gas calculated under

(d)(1)(ii)(A) of this section using the

volumes of oil and gas identified in the

most likely scenario (required under

§ 203.55) described in your previous

complete application for royalty relief.

(C) Perform the same calculations as

required in paragraphs (d)(1)(ii)(A) and

(B) of this section, but use the arithmetic

average of daily closing prices for light

sweet crude oil and for natural gas on

the NYMEX for the 12-month period

preceding the date of your previous

complete application.

(D) If the weighted average price

calculated under paragraph (d)(1)(ii)(B)

of this section is at least 25 percent less

than the weighted average price

calculated under paragraph (d)(1)(ii)(C)

of this section, then you satisfy the

requirements of this paragraph; or

(iii) Prior to starting construction of

your development/production system,

you have revised your estimated

development costs, and they are at least

120 percent of the eligible development

costs associated with the most likely

scenario described in your previous

complete application.

(2)(i) Your request for a

redetermination must include a new

complete application, as discussed in

paragraph (b) of this section and

§ 203.55. MMS will evaluate your

application for a redetermination under

paragraph (c) of this section.

(ii) MMS will determine within 20

working days if your application for a

redetermination is complete. If your

application is incomplete, MMS will

provide you with an explanation of

what it needs to become complete. If

MMS later determines that your

application does not meet any of the

criteria under (d)(1)(i),(ii), or (iii) of this

section, it will consider your

application incomplete.

(iii) When MMS determines that your

application is complete, MMS will

evaluate the application within 120

days. MMS may extend the 120-day

evaluation period for an additional 30

days if necessary to complete the

evaluation. If you agree, MMS also may

extend the 120-day period for more than

30 days.

(iv) If MMS must audit sunk costs to

evaluate your application, MMS may

request that the 120-day evaluation

period be tolled from the time you

receive notice from MMS until you

provide the records necessary to

conduct the audit.

(v) If MMS determines during the

evaluation period that it cannot evaluate

your application because:

(A) Vital information is missing;

(B) The data and information

provided in support of the application

are inconclusive; or

(C) Of any other valid reason; MMS

may request that the 120-day evaluation

period be tolled from the time you

receive notice from MMS until you

provide the needed data, explanations,

or revisions.

(e) When may MMS withdraw

approval of an application for royalty

relief?
Federal Register / Vol. 61, No. 106 / Friday, May 31, 1996 / Rules and Regulations 27277

MMS will withdraw approval of your

application for royalty relief if:

(1) You change the type of

development system proposed in your

approved application (e.g., change from

stand-alone to tieback or vice versa);

(2) You fail to start construction of the

approved development/production

system within two years of the date

MMS approved your application—

notwithstanding any suspension granted

under § 250.10 of this chapter; or

(3)(i) The actual development costs

reported in your pre-production report

(paragraph (c)(4) of this section) are less

than 80 percent of the development

costs from the date of application to the

date of the pre-production report

associated with the most likely scenario

described in your approved application.

In this case, you may retain 50 percent

of the amount of the royalty suspension

volume that MMS previously granted.

(ii) If MMS granted you a royalty

suspension volume after you requested

a redetermination under paragraph

(d)(1)(iii) of this section, MMS may

withdraw approval of your application

for a royalty suspension if your actual

development costs in your preproduction report (paragraph (c)(4) of

this section) are less than 90 percent of

the eligible development costs from the

date of application to the date of the

pre-production report associated with

the most likely scenario described in

your approved application.

(iii) If MMS discovers that the actual

development costs are less than the

amounts specified in paragraphs (e)(3)(i)

or (ii) of this section, MMS will

withdraw retroactively its approval of

the royalty suspension volume. You will

owe royalties and interest on all

production that was subject to the

previously granted royalty suspension.

(4) If MMS determines that you

provided false historical or intentionally

inaccurate information that was material

to MMS in granting royalty relief under

this section, MMS will rescind its

approval as of the date of the approval.

You must pay royalties and late

payment interest determined under 30

U.S.C. 1721 and § 218.54 of this chapter

on all volumes for which you used the

royalty suspension. You also may be

subject to penalties under other

provisions of law.

(5) If MMS withdraws its approval of

a royalty suspension for any of the

reasons in paragraphs (e)(1), (2) or (3) of

this section, you may apply again for

relief under paragraph (b) of this section

and § 203.55.

(f) What happens if MMS fails to

accept or reject my application in a

timely manner?

(1) For applications for fields from

which no royalties were due on

production, other than test production,

prior to November 28, 1995, if MMS

does not make its determinations on

your application within the time period

specified in paragraph (c)(1) or (d)(1) of

this section, including any applicable

extension, you will receive the

minimum royalty suspension volumes

specified in paragraph (h)(1)(i) of this

section.

(2) For PSEP applications, if MMS

does not make its determinations on

your application within the time period

specified in paragraph (c)(1) or (d)(2) of

this section, including any applicable

extension, you will receive a royalty

suspension for the first year of the

project’s production.

(g) How do I appeal an MMS decision

under 203.53?

(1) MMS’ decision whether to grant

deep-water royalty relief and its

decision on the size of the royalty

suspension volume are final agency

actions. You have no right to further

administrative review, including

Secretarial review, of these decisions.

The MMS’s decisions are judicially

reviewable under section 10(a) of the

Administrative Procedure Act (5 U.S.C.

702) only if you file an action within 30

days of the date you receive MMS’s

decision. MMS’s will send its decision

to you by certified mail, return receipt

requested.

(2)(i) Except as provided in paragraph

(g)(2)(ii) of this section, MMS decisions

on designating a lease as part of a field

are final agency actions.

(ii) If MMS designates your lease as

part of a field, within 15 days of such

designation you may file a written

request with the Director for

reconsideration accompanied by a

statement of reasons. The Director will

respond in writing either affirming or

reversing the decision. The Director’s

decision is the final decision of the

Department.

(h) How does a royalty suspension

volume apply to your production?

This paragraph explains how the

royalty suspension volumes in section

302 of the OCS Deep Water Royalty

Relief Act, apply to production from

PDWL’s. For purposes of this paragraph,

any volumes of production that are not

royalty bearing under the lease or the

regulations in this chapter do not count

against royalty suspension volumes.

Also, for purposes of this paragraph,

production includes volumes allocated

to a lease under an approved unit

agreement. The following provisions

apply only to those leases for which the

lessee(s) applies for and receives a

royalty suspension volume under this

section.

(1) For fields from which no royalties

were due on production, other than test

production, prior to November 28, 1995:

(i) The water depth of a lease is based

on the water depth delineations in the

‘‘Royalty Suspension Areas Map’’ in

effect at the time of your application. If

the application for the field includes

leases in different water depth

categories, the minimum royalty volume

associated with the deepest lease

applies. The minimum royalty

suspension volumes are: (A) 17.5

million barrels of oil equivalent

(MMBOE) in 200 to 400 meters of water;

(B) 52.5 MMBOE in 400 to 800 meters

of water; and

(C) 87.5 MMBOE in more than 800

meters of water.

(ii) If your PDWL is the only lease on

the field, you do not owe royalty on the

production from your lease up to the

royalty suspension volume MMS

granted.

(iii) If a field consists of more than

one PDWL, payment of royalties on the

PDWLs’ production is suspended until

their cumulative production equals the

royalty suspension volume MMS

granted. The royalty suspension volume

for each lease equals each lease’s actual

production (or production allocated

under an approved unit agreement)

until cumulative production equals the

field’s royalty suspension volume.

(iv) If a PDWL or an eligible lease, as

defined in § 260.102 of this chapter, is

added to a field for which MMS has

granted a royalty suspension volume

under this section, the field’s royalty

suspension volume will not change. The

additional lease may receive a royalty

suspension volume only to the extent of

its production from the field before the

cumulative production from the field

equals the royalty suspension volume

MMS approved. However, before your

PDWL may participate in the royalty

suspension volume already granted to

the field, you must apply for royalty

relief using an abbreviated form

available at the Gulf of Mexico OCS

Regional Office.

(v) If your PDWL is part of a field that

already has a royalty suspension volume

for eligible leases under § 260.110 of

this chapter, and you apply and qualify

for royalty relief under this section, all

the leases in the field share a single

royalty suspension volume that is the

greater of the volume established for the

eligible leases under § 260.110 of this

chapter or the volume MMS determines

under this section.

(2) For a PSEP:

(i) If your PDWL is the only lease

included in the project, you do not owe
27278 Federal Register / Vol. 61, No. 106 / Friday, May 31, 1996 / Rules and Regulations

royalty on the incremental production

from the project up to the royalty

suspension volume MMS granted.

(ii) If the project includes more than

one lease, the royalty suspension

volume for each lease equals each

lease’s actual incremental production

from the project (or production

allocated under an approved unit

agreement) until cumulative

incremental production for all leases in

the project equals the project’s royalty

suspension volume.

(3) Your lease may receive more than

one royalty suspension volume. You

may apply for royalty relief under this

section for each field that includes your

lease, and each field would receive a

separate royalty suspension volume if it

meets the evaluation criteria of

paragraph 203.53(c). You may also

apply for relief for a PSEP, even if MMS

has already granted a royalty suspension

volume to the field that encompasses

that project.

(4) You may receive a royalty

suspension volume only if your entire

lease is west of 87 degrees, 30 minutes

West longitude. A field that lies on both

sides of this meridian will receive a

royalty suspension volume only for

those leases lying entirely west of the

meridian.

(5) You must measure natural gas

production subject to the royalty

suspension volume as follows: 5.62

thousand cubic feet of natural gas equals

one barrel of oil equivalent, as measured

at 15.025 psi, 60 degrees Fahrenheit,

and fully saturated.

(6)(i) If in the previous calendar year

the arithmetic average of the daily

closing prices on the NYMEX for light

sweet crude oil exceeds $28.00 per

barrel, as adjusted in paragraph (h)(8) of

this section, the royalty relief authorized

in this section is suspended and any

production of oil is subject to royalties

at the lease stipulated royalty rate.

However, this production counts as part

of the established royalty suspension

volume. By January 31 of the current

calendar year, you must pay the royalty

due plus interest, in accordance with 30

U.S.C 1721 and § 218.54 of this chapter,

on any volume of oil from the previous

year for which you did not pay royalty.

(ii) If the arithmetic average of the

daily closing prices on the NYMEX for

light sweet crude oil from the previous

calendar year exceeds $28.00 per barrel,

as adjusted in paragraph (h)(8) of this

section, you must pay royalties on all

your oil production in the current year.

If the arithmetic average of the daily

closing prices on the NYMEX for light

sweet crude oil for the current calendar

year is $28.00 per barrel or less, as

adjusted in paragraph (h)(8) of this

section, you are entitled to a refund or

credit, with interest, of royalties paid

that year on any royalty suspension

volume for oil production. You must

follow MMS regulations at part 230 of

this chapter for receiving refunds or

credits.

(7)(i) If in the previous calendar year

the arithmetic average of the daily

closing prices on the NYMEX for natural

gas exceeds $3.50 per million British

thermal units, as adjusted in paragraph

(h)(8) of this section, the royalty relief

authorized in this section is suspended

and any production of natural gas is

subject to royalties at the lease

stipulated royalty rate. However, this

production counts as part of the

established royalty suspension volume.

By January 31 of the current calendar

year, you must pay the royalty due plus

interest, in accordance with 30 U.S.C

1721 and § 218.54 of this chapter, on

any volume of natural gas from the

previous year for which you did not pay

royalty.

(ii) If the arithmetic average of the

daily closing prices on the NYMEX for

natural gas for the previous calendar

year exceeds $3.50 per million British

thermal units, as adjusted in paragraph

(h)(8) of this section, you must pay

royalties on all your natural gas

production in the current year. If the

arithmetic average of the daily closing

prices on the NYMEX for natural gas for

the current calendar year is $3.50 per

million British thermal units or less, as

adjusted in paragraph (h)(8) of this

section, you are entitled to a refund or

credit, with interest, of royalties paid

that year on any royalty suspension

volume for natural gas production. You

must follow MMS regulations at part

230 of this chapter for receiving refunds

or credits.

(8) Change the prices referred to in

paragraphs (h)(6) and (7) of this section

during each calendar year after 1994 by

the percentage, if any, by which the

implicit price deflator for the gross

domestic product changed during the

preceding calendar year.

(9) A royalty suspension volume will

continue until the end of the month in

which the cumulative production from

the field or PSEP reaches the established

royalty suspension volume.

§ 203.54 [Reserved]

§ 203.55 What information is required for

the net revenue share royalty relief and

deep-water royalty relief application

supplemental reports?

(a) You must submit the applicable

supplemental reports listed below.

(1) Administrative information and

relief justification.

All royalty relief applications must

contain this report, which must include:

(i) Field name;

(ii) Serial number of leases in the

field, names of the lease the titleholders

of record, the lease operators, and the

identification of whether any lease is

part of a unit;

(iii) The API number and location of

each well that has been drilled on the

field/lease or project;

(iv) Location of any new wells

proposed under the terms of the

application;

(v) Description of field/lease history;

(vi) Statement that the reserves would

not be produced without relief;

(vii) Full information as to whether

royalties or payment out of production

will be paid to anyone other than the

United States, the amount to be paid,

and the amount of reduction in such

payment if relief is granted;

(viii) Amount of relief needed to make

the lease (NRS royalty relief), field

(deep-water royalty relief), or project

economic;

(ix) Confirmation that MMS approved

a DOCD or supplemental DOCD (NRS

expansion of production and deepwater royalty relief application only);

and

(x) A narrative description of the

development activities associated with

the proposed capital investments and an

explanation of proposed timing of the

activities and the effect on production

(NRS expansion of production and

deep-water royalty relief application

only).

(2) Net revenue share economic

viability report.

NRS royalty relief applications must

contain this report. This report must

present cash flow data, including 36

months of historical data and 12 months

of projected data, for the following

items:

(i) Lease production subject to royalty;

(ii) Total revenues;

(iii) Royalty payments out of

production;

(iv) Operating costs;

(v) Transportation and processing

costs;

(vi) Capital expenditures (if

applicable); and

(vii) Well drilling costs (if applicable).

(3) Deep-water royalty relief economic

viability report.

This report should demonstrate that

the project appears economic without

royalties and sunk costs using the model

provided by MMS. A company may

provide supplemental information,

including its own model and model

results. This report must include all of

the items listed below.

(i) Economic assumptions provided

by MMS:
Federal Register / Vol. 61, No. 106 / Friday, May 31, 1996 / Rules and Regulations 27279

(A) Starting oil and gas prices;

(B) Real price growth;

(C) Real cost growth or decline rate,

if any;

(D) Base year;

(E) Range of discount rates; and

(F) Tax rate (for use in determining

after-tax sunk costs).

(ii) Projected cash flow analysis (from

application date using annual totals and

constant dollar values). All costs, gross

production, and scheduling must be

consistent with the data in the reserve,

engineering, production, and cost

reports, and the three scenarios

(conservative, most likely, optimistic;

provided in the various reports must be

consistent with each other and the

proposed development system. The

analysis must show:

(A) Oil/gas production;

(B) Total revenues;

(C) Capital expenditures;

(D) Operating costs;

(E) Transportation costs; and

(F) Before tax net cash flow.

(iii) Discounted values.

(A) Discount rate used (selected from

within range provided in MMS

guidelines).

(B) Before tax net present value

without royalties, overrides, sunk costs,

and ineligible costs.

(4) Deep-water royalty relief cost

report.

Deep-water royalty relief applications

must contain this report. Report all

actual and projected costs listed in this

paragraph in the format detailed in the

guidelines.

(i) Sunk costs. This includes all

eligible costs, in current dollars and for

which documentation is provided,

actually incurred subsequent to and

including the first discovery well on the

field. Sunk costs count on an after-tax,

expensed basis, using nominal (current

dollar) amounts.

(ii) Delineation and development

costs, based on actual costs or current

authorization for expenditures. These

costs include:

(A) Platform well drilling costs and

average depth;

(B) Platform well completion costs;

(C) Subsea well drilling costs and

average depth;

(D) Subsea well completion costs;

(E) Production system (platform)

costs; and

(F) Flowline fabrication and

installation costs.

(iii) Production costs, based on

historical costs, engineering estimates,

or analogous projects. These costs

include:

(A) Operating costs;

(B) Equipment costs; and

(c) Existing royalty overrides (MMS

will not use the royalty overrides in its

evaluation).

(iv) Transportation costs, based on

historical costs, engineering estimates,

or analogous projects. These costs

include:

(A) Oil and/or gas tariffs from

pipeline or tankerage;

(B) Trunkline/tieback line costs; and

(C) Gas plant processing costs for

NGL’s.

(v) Ineligible costs. These costs

include:

(A) Acquisition costs;

(B) Application fees;

(C) Prospective exploration well costs;

(D) Costs associated with obligations

existing prior to the application; and

(E) Other ineligible costs listed in

§ 203.55(b).

(vi) Uncertainty. You must provide a

cost scenario consistent with each one

of the three field development and

production profiles (conservative, most

likely, optimistic). Express costs in

constant real dollar terms for the base

year. You may also express the

uncertainty of each cost scenario as a

minimum and maximum percentage of

the base value.

(vii) Scheduling. Provide costs on an

annual basis (in real dollars) for each of

the categories in paragraphs (a)(4)(i)

through (a)(4)(vi) of this section.

(viii) Abandonment. Provide the costs

to plug and abandon wells and to

remove production systems for which

costs have not been incurred at the time

of application.

(ix) Pre-production report. You must

file a pre-production report 60 days

before the start of the production subject

to an approved royalty suspension. For

each of the cost categories in the deepwater royalty relief cost report, you

must include actual costs up to the date

when the pre-production report is

submitted. Retain supporting records for

these costs and make them available to

MMS upon request.

(5) Geologic and geophysical report.

Deep-water royalty relief and NRS

production expansion proposal

applications must contain this report.

This report must include all of the items

listed below.

(i) Seismic data:

(A) Non-interpreted 2D/3D survey

lines (8mm tape) (SEGY format or IES

format);

(B) Interpreted 2D/3D seismic survey

lines identifying all known and

prospective pay horizons, wells, and

fault cuts;

(C) Digital velocity surveys in format

of LTL 10/1/90;

(D) Plat map of ‘‘shot points;’’ and

(E) ‘‘Time slices’’ of potential

horizons.

(ii) Well data.

(A) Hard copies of all well logs.

(1) One-inch electric log must show:

(i) pay zones and pay counts; and

(ii) lithologic and paleo correlation

markers at least every 500 ft.

(2) One-inch type log must show

missing sections from other logs where

faulting occurs.

(3) Five-inch electric log must show:

(i) pay zones and pay counts; and

(ii) labeled points used in establishing

Ro and Rt.

(4) Five-inch porosity logs must show:

(i) pay zones and pay counts; and

(ii) labeled points used in establishing

reservoir porosity or labeled points

showing values used in calculating

reservoir porosity such as bulky density

or transit time.

(B) Digital copies of all well logs

spudded before December 1, 1995.

(C) Core data, if available.

(D) Well correlation sections.

(E) Pressure data.

(F) Production test results.

(G) PVT analysis, if available.

(iii) Map interpretations. For each

reservoir included in the application,

you must submit:

(A) Structure maps and top and base

of sand maps showing well and seismic

shot point locations;

(B) Isopach maps for net sand, net oil,

net gas, all with well locations;

(C) Maps indicating well surface and

bottom hole locations, location of

development facilities, and shot points;

and

(D) Identification of reservoirs not

contemplated for development.

(iv) Reservoir data. For each reservoir

included in the application, you must

identify and submit:

(A) Oil and/or gas reserve/resource

distribution;

(B) Probability of reservoir occurrence

with hydrocarbons;

(C) Probability the hydrocarbon in the

reservoir is oil, and the probability it is

gas;

(D) Distributions for the parameters

used to estimate the resources, i.e. acre,

net thickness, recovery, porosity, salt

water saturation, formation volume

factor;

(E) Aggregated BOE reserve/resource

for the field;

(F) Gas/oil ratio distribution for each

reservoir;

(G) Yield distribution for each gas

reservoir;

(H) Description of anticipated crude

quality (e.g., gravity); and

(I) Points on the aggregated reserve/

resource distribution used for the

determination of the three (conservative,

most likely, optimistic) production

profiles specified in the production

report.
27280 Federal Register / Vol. 61, No. 106 / Friday, May 31, 1996 / Rules and Regulations

(6) Production report. Deep-water

royalty relief and NRS production

expansion proposal applications must

contain this report, which must include

all of the items listed below.

(i) Production profile. Submit actual

and projected (BOE) production by year

for each of the following products: oil,

condensate, gas, and associated gas.

(ii) Uncertainty (deep-water royalty

relief only). Submit three production

profiles as described in paragraph

(a)(6)(i) of this section. Each one must

be consistent with a specific point on

the aggregated reserve/resource

distribution and must represent a

conservative, most likely, and an

optimistic case.

(iii) Production drive mechanisms for

each reservoir.

(iv) Quality adjustments to prices for

gravity, sulfur, etc.

(7) Engineering report.

Deep-water royalty relief and NRS

production expansion proposal

applications must contain this report.

However, NRS expanded production

applications should submit this

information only as it relates to the

planned development. This report must

include all of the items listed below.

(i) Development concept:

(A) Tension leg platform, fixed, floater

type, subsea tieback, etc.; and

(B) Construction schedule.

(ii) Planned wells:

(A) Number of wells planned;

(B) Type of well (platform, subsea,

vertical, deviated, horizontal);

(C) Well depth;

(D) Drilling schedule;

(E) Completion description (single,

dual, horizontal, etc.); and

(F) Completion schedule.

(iii) Production system equipment:

(A) Production capacity for oil and

gas and a description of its limiting

component(s);

(B) Unusual problems (low gravity,

high sulfur content, etc.);

(C) Subsea structures;

(D) Flowlines; and

(E) Production system installation

schedule.

(iv) Multi-phase development plans;

(A) Conceptual basis for developing in

phases and goals/milestones required

for commencing subsequent phases; and

(B) Justification for the exclusion of

reservoirs not contemplated for

development.

(v) Uncertainty. Submit schedules for

development consistent with each of the

three field production profiles

(conservative, most likely, optimistic)

provided in the production report.

(b) Ineligible costs. MMS will not

include certain costs in making its

royalty relief determinations. These

include, but are not limited to:

(1) Costs incurred before first

discovery on the field;

(2) Cash bonuses;

(3) Royalty relief application fees;

(4) Lease rentals, royalties, and net

profit share and net revenue share

payments;

(5) Legal expenses;

(6) Damages and losses;

(7) Taxes;

(8) Interest or finance charges;

(9) Fines or penalties;

(10) Designated well costs, including

prospective exploration and delineation

costs; and

(11) Costs associated with prior

existing obligations (e.g., royalty

overrides or other forms of payment for

acquiring a financial position in a lease,

expenditures for plugging wells and

removal and abandonment of facilities

existing on the date of the application).

(c) The applicant or the applicant’s

authorized representative must certify

that all information submitted in an

application or a pre-production report is

accurate and complete. The application

or pre-production report must be

accompanied by a report prepared by an

independent certified public accountant

(CPA) expressing an unqualified

opinion on the accuracy of the actual

historical financial information

presented in the application or preproduction report and that the

presentation of data and information

conforms to the MMS guidelines. The

applicant will make the independent

CPA available to the MMS to respond to

questions which may arise regarding the

evaluation of the historical information.

This requirement does not limit the

MMS’s ability to conduct further review

of the applicant’s records to support the

historical financial information

included in the application.

§ 203.56 Recovery of application

processing costs.

When you submit an application for

royalty relief, you must include a

payment to reimburse MMS for the costs

it incurs in processing your application.

The MMS will establish in a Notice to

Lessees a schedule that will specify the

fees that must be paid for each of the

different types of royalty relief

applications. Regional Directors will

periodically update the fee schedule to

reflect changes in MMS costs as well as

to provide other information necessary

for the administration of our royalty

relief program.

[FR Doc. 96–13626 Filed 5–30–96; 8:45 am]

BILLING CODE 4310–MR–P

DEPARTMENT OF THE TREASURY

Secret Service

31 CFR Part 411

[1505–AA69]

Color Illustrations of U.S. Currency

AGENCY: Secret Service, Treasury.

ACTION: Final rule.

SUMMARY: Pursuant to the Counterfeit

Deterrence Act of 1992, the Secret

Service permits color illustrations of

United States currency provided such

illustrations are consistent with the

requirements set out in this final rule.

Prior to the issuance of this rule, color

illustrations of U.S. currency were not

permitted.

EFFECTIVE DATE: May 31, 1996.

FOR FURTHER INFORMATION CONTACT:

Mark Mulligan, Attorney/Advisor,

Office of Chief Counsel, U.S. Secret

Service, 1800 G Street, N.W., Room 842,

Washington, D.C. 20223, (202) 435–

5771.

SUPPLEMENTARY INFORMATION: On June

26, 1995 (60 FR 32929), the Secret

Service proposed to amend title 31,

chapter IV of the Code of Federal

Regulations by adding part 411 which

would permit color illustrations of U.S.

currency. At the time this proposal was

issued, illustrations of U.S. currency

were only permitted provided the

illustration was in black and white and

was of a size less than three-fourths or

more than one and one-half, in linear

dimension, of each part so illustrated,

and provided the negatives and plates

used in making the illustration were

destroyed after their final use. 18 U.S.C.

504. Color illustrations of U.S. currency

were not permitted.

Interested parties were invited to

participate in the rulemaking

proceeding by submitting written

comments on the proposal. Five

comments were received. The Secret

Service carefully reviewed and

evaluated these comments. In

considering these comments, the Secret

Service carefully weighed the

recommendations and comments with

the federal government’s compelling

interest of preventing the counterfeiting

of U.S. currency.

Specifically, all the commentators to

some extent questioned the need for and

practicality of the requirement that the

term ‘‘non-negotiable’’ be prominently

and conspicuously placed across the

center portion of any color illustration.

After careful consideration, the Secret

Service has decided to amend its

proposal by removing the requirement