Royalty Relief for Producing Leases and Certain Existing Leases in Deep Water

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.

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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

[[Page 27264]]

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

case-by-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

[[Page 27265]]

which we will make royalty suspensions available for new deep-water

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 well-reworking 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.

[[Page 27266]]

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 (Sec. 203.53(b) and Sec. 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

Sec. 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 (Sec. 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 Sec. 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 Sec. 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

[[Page 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 Sec. 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 Sec. 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 deep-water 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

[[Page 27268]]

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 Sec. 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 (Sec. 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

(Sec. 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) (Sec. 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 (Sec. 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

[[Page 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 (Sec. 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

(Sec. 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 deep-water 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 field-wide development, having a

positive net present value as calculated with MMS-stipulated 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 Sec. 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

[[Page 27270]]

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 Sec. 203.55 and

described in the guidelines) in the previous application for royalty

relief. (See Sec. 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 Sec. 203.53(b) and

Sec. 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.

[[Page 27271]]

We will use the pre-production report (Sec. 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

Sec. 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

Sec. 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

Sec. 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 deep-water 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 Sec. 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 Sec. 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

(Sec. 203.53(g)(5)). This is the conversion factor traditionally used

in the Gulf of Mexico and is the same factor specified in

Sec. 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

[[Page 27272]]

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

Sec. 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 deep-water 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 lease-stipulated 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

deep-water 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

[[Page 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 deep-water

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

------------------------------------------------------------------------

Responses Hours per Hours per

Type of application per year response 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

------------------------------------------------------------------------

Responses Hours per Hours per

Type of Application per year response 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 pre-

production report must be accompanied by a report prepared by an

independent certified public accountant as described in section

203.55(c) of the rule.

[[Page 27274]]

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

Sec. 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

Sec. 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

Sec. 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 fixed-leg

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 Sec. 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.

Sec. 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 Sec. 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,

[[Page 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 Sec. 203.53 (Royalty relief for

certain deep-water leases in the Gulf of Mexico).

Sec. 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

Sec. 203.52(b) and Sec. 203.55. An application fee in accordance with

Sec. 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.

Sec. 203.53 Royalty relief for certain deep-water 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 Sec. 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

Sec. 203.53(d)(1);

(B) MMS has withdrawn approval of a previously granted royalty

suspension under Sec. 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 Sec. 203.53(d).

(ii) When MMS determines that your application is complete, MMS

will

[[Page 27276]]

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 pre-production report 60 days before the planned start of

production which is subject to the royalty suspension volume, as

specified at Sec. 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 three-dimensional 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

Sec. 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

Sec. 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?

[[Page 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 Sec. 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 pre-production

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 Sec. 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

Sec. 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 Sec. 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 Sec. 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 Sec. 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

[[Page 27278]]

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 Sec. 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 Sec. 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.

Sec. 203.54 [Reserved]

Sec. 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 deep-water 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:

[[Page 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 Sec. 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 deep-water

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.

[[Page 27280]]

(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 pre-production 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.

Sec. 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