[Federal Register Volume 61, Number 106 (Friday, May 31, 1996)]
[Rules and Regulations]
[Pages 27263-27280]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 96-13626]
=======================================================================
-----------------------------------------------------------------------
DEPARTMENT OF THE INTERIOR
Minerals Management Service
30 CFR Part 203
RIN 1010-AC13
Royalty Relief for Producing Leases and Certain Existing Leases
in Deep Water
AGENCY: Minerals Management Service (MMS), Interior.
ACTION: Interim Rule and Information Gathering.
-----------------------------------------------------------------------
SUMMARY: This interim rule establishes conditions for granting royalty
relief on producing leases through their conversion to Net Revenue
Share (NRS) leases, provides for suspensions of royalty payments on
certain deep-water leases issued as the result of a lease sale held
before November 28, 1995, and defines the information required for a
complete application for royalty relief.
DATES: This interim rule is effective July 1, 1996.
We will consider all comments we receive by July 30, 1996. We will
begin review of comments at that time and may not fully consider
comments we receive after July 30, 1996.
ADDRESSES: Mail or hand-carry comments to the Department of the
Interior; Minerals Management Service; Mail Stop 4700; 381 Elden
Street; Herndon, Virginia 22070-4817; Attention: Chief, Engineering and
Standards Branch.
FOR FURTHER INFORMATION CONTACT: Dr. Marshall Rose, Economic Evaluation
Branch, telephone (703) 787-1536.
SUPPLEMENTARY INFORMATION:
I. Objectives of Royalty Relief
Royalty relief can lead to increased production of natural gas and
oil, creating profits for lessees and royalty and tax revenues for the
government. By this rulemaking, the Secretary seeks to establish
economic incentives to encourage Outer Continental Shelf (OCS) lessees
to incur the expenses or make the capital investments necessary to
maintain or increase production. To the extent possible for approved
applications, we will reduce or suspend royalty payments to permit
lessees to earn a reasonable return on their capital investment for
projects involving new investment. For projects not involving new
investment, we will provide relief sufficient to allow an operating
profit in cases where expenses plus royalties exceed revenues.
The Secretary will implement these royalty relief provisions in
conjunction
[[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
