[Federal Register Volume 63, Number 11 (Friday, January 16, 1998)]
[Rules and Regulations]
[Pages 2605-2626]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 98-842]
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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: Final rule.
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SUMMARY: This rule establishes conditions for reducing royalties on
producing leases; provides for suspension of royalty payments on
certain deep water leases issued as the result of lease sales held
before November 28, 1995; and describes the information required for a
complete application for royalty relief.
EFFECTIVE DATE: This rule is effective February 17, 1998. However, the
information collection requirements contained in Sec. 203.61 will not
become effective until approved by the Office of Management (OMB). MMS
will publish
[[Page 2606]]
a document at that time announcing the effective date.
FOR FURTHER INFORMATION CONTACT: Dr. Marshall Rose, Chief, Economics
Division, at (703) 787-1536.
SUPPLEMENTARY INFORMATION:
I. Objectives of Royalty Relief
Royalty relief can lead to increased development and production of
natural gas and oil, creating profits for lessees and royalty and tax
revenues for the government that it might not otherwise receive. This
rule establishes economic incentives that encourage Outer Continental
Shelf (OCS) lessees to spend or invest the money needed to promote
development and encourage increased production. For all Federal
offshore planning areas, we may provide enough relief to allow a
reasonable operating profit if expenses plus royalties are approaching
revenues. For cases in certain deep water (water at least 200 meters
deep) planning areas of the Gulf of Mexico (GOM), we may suspend
royalty payments to permit lessees to earn a reasonable return on their
capital investments.
The Secretary of the Interior (Secretary) carries out royalty
relief as part of his stewardship and sound management of public lands.
This includes conserving resources, getting a fair return to the public
on OCS resources, and ensuring 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. Section 8(a)(3)(A)of the Outer Continental Shelf
Lands Act (OCSLA), as amended (43 U.S.C. 1337(a)(3)(A)), gives the
Secretary authority to reduce royalties on leases in order to increase
production. Relief must be justified and granted case by case.
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 section 8(a) of the OCSLA (43 U.S.C. 1337(a)(3)(B))
authority so the Secretary may grant relief on a producing or non-
producing lease, or category of leases. Its purpose is to promote
development or increased production, or to encourage production of
marginal resources, for GOM leases lying west of 87 degrees, 30 minutes
West longitude.
The DWRRA also covers leases issued in water depths greater than
200 meters (deep water) as a result of sales held before the DWRRA's
enactment. Section 302 of the DWRRA singles out ``new production'',
from a lease or unit existing on the date of its enactment and in the
GOM's deep water west of 87 degrees, 30 minutes West longitude. The
amended OCSLA (43 U.S.C. 1337(a)(3)(C)) says this new production
doesn't qualify for royalty suspension if the Secretary determines that
this new production would be economic without royalty relief.
Otherwise, the Secretary must determine for each case how much
production to exclude from royalty in order to make the new production
economic.
Existing leases or units having no royalty-bearing production,
other than test production, before November 28, 1995, and qualified for
relief under Section 302, need not pay royalties from a field on the
first:
17.5 million barrels of oil equivalent (MMBOE) for leases
in fields in 200 to 400 meters of water,
52.5 MMBOE for leases in fields in 400 to 800 meters of
water, and
87.5 MMBOE for leases in fields in more than 800 meters of
water.
These leases or units may qualify for a larger suspension volume if
this specified volume wouldn't make the field economic.
Under Sec. 8(a) of the OCSLA as amended by Sec. 302 of the DWRRA,
we may also grant a royalty-suspension volume for production from lease
development involving a substantial capital investment (e.g., fixed-leg
platform, subsea template and manifold, tension-leg platform, multiple
well projects, etc.) proposed in a Development Operations Coordination
Document (DOCD), or a supplement to an approved DOCD, approved by the
Secretary after November 28, 1995. This type of relief is available to
leases that produced before November 28, 1995. In this case, we'll
grant the suspension volume we determine necessary to make the new
production economic.
We issued the Interim Rule for Royalty Relief for Producing Leases
and Certain Existing Leases in Deep Water on May 31, 1996 (61 FR
27263). We asked for comments, received many, and are now issuing a
final rule.
III. Response to Comments
Fifteen respondents--the American Petroleum Institute (API), the
National Ocean Industries Association (NOIA), the Independent Petroleum
Association of America (IPAA), and 12 oil and gas companies--submitted
comments on the Interim Rule and the supplementary guidelines. We
analyzed all comments and sometimes revised the final language based on
them. We first address the general concern expressed about the Net
Revenue Share (NRS) royalty relief system, followed by the three main
themes raised in the comments on the Deep Water royalty relief system.
Finally, we provide responses to the other individual comments and
answer questions relating to selected provisions retained from the
Interim Rule.
Comment on Utility of NRS Relief
Comment: The regulations dealing with NRS leases will be of little
or no utility. Regarding leases with inadequate revenues to sustain
production, the qualifying requirement stipulating that royalty
payments must be at least 75 percent of net revenues over the most
recent 12-month period is unrealistic and too stringent (Secs. 203.50,
52 and 53).
Response: We've chosen to keep the two principal features of the
proposed NRS system. These are a qualification requirement based on a
75 percent royalty share of net revenue and a feature whereby the
average lease rate gradually rises back to the pre-relief level when
production made possible by the relief rises sufficiently. However,
we've made changes in this form of relief that will make it easier to
implement and operate under the NRS system. These changes will reduce
the application burden, simplify the qualification requirements, and
modify the operational framework.
We proposed the NRS system to implement the OCS Lands Act (43
U.S.C. 1337(a)(3)(A)) authority to offer royalty relief to a producing
lease to promote increased production. We specified different
qualification conditions for two situations: end-of-life leases with
inadequate revenues to sustain production and marginally economic
projects to expand production. We've decided to no longer offer a
separate form of royalty relief for expansion projects, because lessees
with such projects should generally prefer applying for, and operating
under, the revised end-of-life relief system in this final rule. Also,
by dropping project relief we've simplified the program by eliminating
the need for the applicant to show that production would be economic
only with relief and that the project would add at least 1 year's worth
of production. To emphasize this narrower scope and avoid confusion
with an NRS system that has been generally avoided by industry, we've
adopted the new name ``end-of-life relief.'' However, we have retained
the underlying conceptual framework of the proposed NRS system in the
new end-of-life royalty relief system.
For end-of-life situations, the interim rule required a
demonstration that
[[Page 2607]]
royalties were taking 75 percent of net revenues and were projected to
take an increasing share in the future. We designed these stipulations
to fulfill the ``increase production'' condition in the statute.
However, we now believe that the increasing share requirement added
little to the assurance that royalty relief would result in increased
production. Also, it was burdensome and placed us in a position of
relying unnecessarily on projections made by the applicant.
Accordingly, we've dropped the increasing share condition.
Moreover, we've reduced the extent of information that must be
submitted in an application. Instead of 36 months of cost history and
12 months of prospective data, under the new end-of-life system,
applicants provide cost and production for the 12 out of the past most
recent 15 months that have average daily production of at least 100
barrels of oil equivalent (BOE). Note the 100 BOE per day threshold
applies to whole leases, not individual wells. The 12 out of 15 months
provision protects producers from being disqualified by temporary shut
down events like well work-overs, and it mitigates misrepresentations
due to seasonal variation. The 100 BOE average daily production
requirement gives us more assurance than the previous proposed
``increasing share'' requirement of the interim rule that relief would
make the increased production economic. We believe that leases with
production smaller than 100 BOE cannot cover platform operating costs
and that they likely continue to operate for reasons beyond those that
royalty relief would affect. That is, while royalty relief may reduce
losses for under 100 BOE/day operators, it will not increase production
from them.
The proposed NRS relief system took 50 percent of increases or
decreases in net revenue, regardless of the cause. We designed this
feature to allow the public to share automatically in unforeseen
expansions of production, price increases, or cost decreases while
cushioning lessee losses from unforeseen deterioration in these
factors. The absence of applications suggests to us that these
advantages were outweighed by a perception that the NRS system imposed
on lessees a heavy and ongoing data collection burden and extracted
from them too much of their upside profit potential.
Fortunately, we've found that a simpler and less burdensome royalty
system can approximate the sliding rate structure of the NRS system.
Therefore, we've replaced the NRS terms, which typically included a 50
percent rate over any possible level of production, with a 2-tier
royalty rate. We give you relief with a rate fixed at one-half the pre-
relief rate for a specific monthly amount of production followed by an
incremental rate fixed at 50 percent above the pre-relief rate for
production above that monthly amount. We added other features to
balance the end-of-life system. Features that encourage lessees include
a cap on the average royalty rate at the pre-relief rate and a lessee
option to end relief at any time. Features that protect public interest
include lifting of relief during periods of very high prices, an
eventual end of relief if prices or production, or both, remain high
for an extended period, and a provision allowing us to identify
conditions in individual cases which would lead to terminating the
relief arrangement because those conditions are inconsistent with an
end-of-life situation.
Main Themes in Comments on the Deep Water Interim Rule
1. Qualification Circumstances
Comment: The current interim rule is too complex. As an
alternative, API, NOIA, and IPAA suggest setting minimum economic field
sizes (MEFS) by water depth and development system that automatically
qualify fields for royalty relief (Sec. 203.67).
Response: Automatic MEFS are too impractical and difficult to
develop and maintain. So, we won't use them to decide if a field
qualifies for the amount of royalty relief the DWRRA specifies.
We estimate that calculating an MEFS requires values for more than
90 parameters, such as price, quality, water and drilling depth, gas-
to-oil ratio, production rates, and scheduling of costs and production.
We'd need to calculate many MEFS and would have to update them
regularly as prices, costs and other significant values change. With
large amounts of relief and rapidly changing values, and given the
nearly explicit statutory mandate to provide sufficient relief, but not
too much, we'd have to carefully set the qualifying field sizes. As a
result, we'd not be able to set MEFS at sizes that would be worth
developing even with royalty relief.
In contrast, the potential number of non-producing leases that may
come in for relief looks relatively small. These are pre-Act leases,
formerly pre-enactment deep water leases, or PDWLs. We can now identify
fewer than 75 fields in this category, a small fraction of which may
need relief. More importantly, we can't justify relying on generic data
to determine an MEFS when an application gives us specific data for
each field.
2. Early Relief Indication
Comment: MMS requires that a DOCD be approved before an applicant
can submit a complete application for royalty relief on a pre-Act
lease. Unfortunately, that pushes the request for royalty relief too
late into development to be useful. Lessees won't prepare expensive
DOCDs for projects that might not go into production, so they want some
assurance royalty relief will be granted before preparing one
(Sec. 203.83).
Rather than require an approved DOCD before submission of an
application, break approval into two phases. In phase one, an applicant
would file a preliminary application early in the life of a project
based on the best information available at the time but with
significantly less data than required in a final application. Based on
a less extensive review than required for a final application, MMS
would give a preliminary finding about whether the project qualified
for relief and the appropriate suspension volume. Unless there were
material changes, the preliminary finding would be binding. In phase
two, a final application would either confirm the relief or cause MMS
to do a new evaluation because of material changes (Sec. 203.61).
Response: We agree that the DOCD requirement is unnecessarily
restrictive and have removed it in the final rule. Instead, we'll
depend on other means to ensure appraisals are complete enough for the
applicant to make an informed decision to develop and for us to
evaluate the need for royalty relief. We will:
Shorten the period allowed from 2 years to 1 year between
the approval of relief and the start of construction on the development
and production system,
Allow significant new geological and geophysical (G&G)
data to qualify only for the initial redetermination, and
Use our own professional judgment on whether the appraisal
is sufficient for decision making.
Breaking the approval into two phases as proposed by industry
comments has a number of flaws. MMS would have to make a conditionally
binding relief decision in phase one with less data and certainty than
the company would have when it decides whether to develop after phase
two. Foregoing Federal property rights to royalty income under the
existing lease contract without sufficient information would be too
arbitrary. Also, our conditional approval may discourage an applicant
from developing more information that might
[[Page 2608]]
change the preliminary finding, before filing a phase two application.
We've changed the rule to fit industry's request for an assessment
of relief early in the project. In certain circumstances, a lessee or
operator may request a nonbinding assessment of whether a field would
qualify for royalty relief before submitting the first complete
application on a field. This option will help those who don't want to
risk having to meet qualifications for a redetermination if we reject a
complete application, but want to know early about the chances for
royalty relief on a marginal prospect.
The request would involve a draft application plus a processing
fee. It could come any time after discovery (after a well qualifies
under 30 CFR 250.11 or production is allocated under an approved unit
agreement). The detail must be comparable to a complete application to
ensure we assess the same prospect the lessee or operator envisions. We
would develop a nonbinding assessment presuming that continued
appraisal would produce expected values for unknown, but essential,
data. Therefore, applicants must also send in an appraisal plan to
drill one or more wells should MMS issue a favorable nonbinding
assessment. After at least 90 days, a final, complete application can
confirm or revise the data in the draft application and present the
applicant's binding proposal as a condition for receiving royalty
relief.
3. Complexity of Methods and Data Requirements
Comment: MMS proposes to use Monte Carlo simulations to account for
the uncertainty in application data. Probability distributions in Monte
Carlo techniques may be appropriate to analyze exploration and evaluate
the adequacy of lease sale bids for which most data are unavailable and
estimated. However, these approaches are less appropriate to analyze
development. After discovering hydrocarbons, drilling delineation wells
and taking seismic readings, the data are much more certain. Companies
typically use simple scenario modeling and sensitivity analyses on
development projects. MMS should adopt the scenario approach most used
by industry (Secs. 203.85-89).
Response: We've kept the Monte Carlo methods, though somewhat
simplified, for several reasons. No clear milestones show when
appraisal or delineation is adequate for making the development
decision, so scenario modeling would not be suitable for many
applications. Also, we must systematically handle the uncertainty
associated with applications to be submitted at an early stage of
development and we've been given a mandate to deal with the extra risk
deep water poses. The Monte Carlo approach handles these diverse
situations and requirements by allowing for the incorporation of as
much or as little risk as perceived, a full range of sensitivity
analysis, and the small but positive chance for all the circumstances
an operation needs to become highly profitable.
We differ from the scenario approach industry describes mainly in
the way we estimate reserves. The scenario approach offers no
systematic way to arrive at a reserve size and chance of occurrence. We
use careful descriptions of reservoirs and a standard procedure for
calculating resources and aggregating them to the field level.
Generally, we have adopted the reserves and resource definitions of the
Society of Petroleum Engineers. This standardized procedure treats all
applicants alike. It keeps our evaluators from having to learn the
subtleties of each applicant's definition of reserves in order to
verify and perhaps change that part of the evaluation. The level of
detail proposed will ensure that we apply a consistent, analytically
supportable method, especially for estimating producible reserves and
resources.
The G&G report requests measurable reservoir data to help us
validate inputs to the evaluation model. Distributions for all data
items provide a way to document the uncertainty about these factors,
but we don't need estimates for all data items because the model
combines some items and derives other inputs. We've tried to clarify
and simplify the data requirements in the spirit of the ``scenario''
approach.
Under our Monte Carlo procedure, applicants may use up to three
discrete development scenarios, and they may include ranges for many of
their variables. We need this detail so we can clearly understand the
options and uncertainties an applicant faces. Our model has a less
complex structure than publicly available models for estimating
reserves and evaluating economics.
Individual Comments on the Deep Water Interim Rule and Guidelines
The following tables respond to the comments we received on the
interim rule and supplementary guidelines. Each row references
appropriate sections in the final rule and subject areas in the interim
rule that relate to that comment and response.
Comment on General Provisions
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Requirement/Subject Comment MMS Response
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203.3/Processing Fees The fees for royalty relief are We estimate fees based on how
too high and more than cover the many hours of work we expect the
costs of processing and average application to take.
deterring nuisance applications. After we have more experience
Applicants should get refunds if with applications, we'll review
fees are more than actual processing costs and adjust fees
processing costs, which could be if necessary. We plan to give
the case if screens for minimum refunds only for incomplete
field size are used to approve applications. But, we won't
relief. charge more when processing
costs exceed the established
fees.
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Comments on Net Revenue Share (NRS) Royalty Relief
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Requirement/Subject Comment MMS Response
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203.52/NRS Relief--Approval Criteria for If a lease produces from two or Relief for end-of-life cases is
Multiple-field Leases more fields, one or more of designed for and granted to a
which do not qualify for NRS whole lease or unit, not to a
relief, royalty relief should project or field. If a lease as
still be possible for the lease a whole qualifies for end-of-
production which would otherwise life relief, it gets it
qualify. regardless of how many fields
are involved.
[[Page 2609]]
Guidelines--Supplementing 203.53/Relief Requiring the operator to act as Agree. We've dropped this
Operation a single payor could not have requirement. It was proposed
been anticipated at the time the because the scope of an audit
producer agreed to become the for a lease receiving royalty
operator and exposes the relief is greater than for
operator to unforeseen legal normal leases. A single payor is
implications or burdens. Getting designated to keep our audit
money and accurate information expenses reasonable wherever
to pay and report royalties from multiple lease owners enjoy
other lease owners is difficult, relief. However, the Royalty
if not impossible, and could Simplification and Fairness Act
obligate the operator for late contains language which
or improper payment and precludes our insistence on a
reporting interest and penalties. single payor.
203.56/NRS Relief--Lease Transfers or If a lease is assigned, the NRS In concept, relief is granted to
Assignments terms should be transferred to a lease or unit, not to a
the assignee upon request. If lessee. We've changed the rule
the assignee doesn't ask to to automatically transfer relief
retain NRS terms, the lease terms to the assignee. Lessees
should revert to the standard also have the option to end
lease royalty rate. relief at anytime.
----------------------------------------------------------------------------------------------------------------
Comments on Deep Water Royalty Relief (DWRR)
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Requirement/Subject Comment MMS Response
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203.60 & 78/Field Definition MMS should elevate the level for field definition Agree in part. The
Decision Level & Appeals. decisions, notify lessees of the field designations, Chief, Reserves
and allow them to object. It should also extend the Section, Office of
period for appealing a field decision from 15 to 30- Resource
60 days. And it should allow companies to review Evaluation, GOM
current field designations for the GOM and industry Region (GOMR), will
input in any revisions make field
decisions after a
lease has been
qualified as
producible. As part
of that process,
affected lessees
and operators will
be able to review
and discuss any
data with us before
we make the final
field decision. We
won't extend the
formal appeal
period after this
decision. Until the
GOMR issues a final
decision on the
field designation,
lessees of a pre-
Act lease can't
apply for DWRR.
However, a DWRR
application based
on the GOM Regions'
final field
designation
decision can be
filed and processed
while the field
designation is
under appeal.
203.60/Field Concept and Industry is accustomed to delineating a field for Agree. The term
Designation--Methodology. reasons of infrastructure, not geology, so ``field'' in
disagreements over ``field'' designation can be geological and
expected. Recommend that MMS make public the methods petroleum
it uses to identify fields and work with industry to literature is
develop a more precise definition for ``field.'' usually defined
relative to
geologic structure
or stratigraphic
conditions. The
Field Naming
Handbook, already
available on the
INTERNET from the
GOMR, explains our
methods. The GOMR
will gladly
entertain
suggestions for
improvements.
Meetings on a field
designation before
starting the
completeness review
can improve
understanding. But
the basic entity
for relief on
royalties in deep
water is the
geologic field, not
the project.
Deep Water Guidelines Will MMS answer questions on preparing an application Yes. As the revised
Supplementing 203.62/ before it is filed and a fee paid? guidelines state,
Applications--Informal Consulting. we'll informally
advise you how to
fill out an
application, but
not whether to file
one. Given the
extensive
guidelines and
model
documentation,
informal advice can
save you time
before filing and
us time during the
completeness review
and evaluation.
203.62 & 65(f)/Applications & The economic, geologic, and engineering reports are Agree in part.
Revising Applicants' Assumptions. too complicated, voluminous, and costly for marginal Application
opportunities that depend on royalty relief. But MMS requirements impose
should not revise any assumptions without consulting a small cost in
the applicant and, if necessary, letting a third comparison to the
party settle disputes. At the very least MMS should size of the royalty
justify any revisions to an applicant's assumptions relief at stake.
We'll use our
judgment and
discretion in
deciding whether to
ask an applicant
for more
information or for
clarification
before making any
changes, tolling
the clock as needed
to complete a full
evaluation.
We also will
identify changes in
related variables
that may need to be
discussed. Where
major assumptions
are unsupported by
backup or important
data elements are
inconsistent with
other parts of the
application, we'll
fully explain the
source of the
problem and provide
a chance to explain
or resolve the
outstanding issues
before deciding on
an application. We
aren't planning to
use third parties
to resolve
disputes.
203.63/Applications--Joint Industry is pleased that DWRR doesn't mandate If lessees want
Application Difficulties. unitization. However, joint applications may be DWRR, they will
unworkable due to different reserve numbers, costs, have to at least
etc., estimated by different lessees design applications
jointly and, if
approved, make sure
they meet
performance
conditions for
retaining relief.
In cases where a
party refuses to
cooperate in
submitting a joint
application, it
won't be eligible
to receive any
relief granted, and
we'll likely need
to make assumptions
about how it might
have participated
in and contributed
to joint
development of the
field.
[[Page 2610]]
203.63/Applications--Joint MMS shouldn't require lessees that share the same Joint applications
Application Coercion. geologic structure to file joint applications because don't require joint
this requirement could inhibit applications or development, but
restrict how companies operate offshore. For they are an
instance, on multi-lease fields, an economic project inescapable feature
might negate another's less robust project; or a more of a field-based
advanced project may refuse to co-operate with a system. The rules
competitive, but lagging, project, etc allow good-cause
exceptions to joint
applications.
Should other
lessees on the
field choose not to
apply for relief,
they're still free
to develop their
leases as they
wish, but they
won't share any
relief granted.
203.64/Applications with A limit of one application per field restricts a The limit is
Assignments. company from seeking relief on a farmed-out lease if intended in part to
the prior owner applied for relief on that field and close the potential
was rejected. The new company that thinks it could loophole of
develop the field with royalty relief must qualify assigning leases to
for a redetermination to apply get around
requirements for
redetermination.
203.65/Review and Evaluation-- MMS should notify all affected lessees when royalty Agree. We will
Notification of MMS relief is granted and publish when, who, and how much notify all
Determinations. relief is given designated lease
operators within a
field when royalty
relief is granted.
The basic summary
information will be
published on MMS's
and GOMR's home
pages on the
INTERNET.
203.65/Review and Evaluation-- MMS's determination review is too long and will delay Public law sets the
Determination Period. field development because lessees can't invest allowed review
without knowing whether royalty relief will be periods. However,
available. Reduce the review time to 3 months we don't plan to
use the entire time
if we can do
determinations
faster. Yet careful
review often
requires time,
especially when new
and complex
developments are
proposed and huge
amounts ($100
million plus) of
royalty relief and
taxpayer assets are
at stake.
203.65/Review and Evaluation-- The clock should be tolled by using one measure of DWRRA stipulated
Tolling the Clock--Measurement. time, either work days or calendar days calendar days for
its deadlines of
120 or 180 days for
approval or
rejection. We'll
continue to use
work days for
reviewing
applications for
completeness
because of the
short time allowed.
MMS must review
each application
thoroughly to
ascertain whether
it is complete
before we start the
statutory clock in
calendar days to
analyze economic
viability. Industry
is accustomed to
our using work days
to conduct
completeness checks
for other filings.
203.65/Review and Evaluation-- Evaluation time should be tolled ``upon receipt by the Agree. As the rule
Method for Tolling the Clock. applicant of written notification'' of an information states, the
deficiency and the clock should be restarted ``upon evaluation clock
receipt of the needed information in the [GOM] will be stopped
Regional MMS office.'' when the applicant
receives written
notice from us and
will begin when the
requested
information is
received in the
regional office.
Deep Water Guidelines How will MMS account for costs and production Each application and
Supplementing 203.65/Review and (revenues) that it believes should be added to the scenario presents a
Evaluation--Consistency with economic evaluation of a field because they are unique proposal.
Differences in Geologic associated with developing reservoirs omitted from an We'll adjust data
Interpretation. application? as necessary. For
example, if we
determine that an
applicant omitted
prospective
reservoirs, it's
reasonable to
assume they'll be
found and developed
later. By adding
the necessary costs
after production
begins, we avoid
the complexity of
having to adjust
the estimated pre-
production costs
used as a
performance
condition.
203.67/Review and Evaluation--Dual Eliminate the dual test, at least for applicants We've kept the dual
Test Role in Evaluation Model seeking only the minimum suspension volume. MMS test, but have
(Royalty Suspension Viability should grant relief and not interject itself into the modified the
Program (RSVP)). process by which a lessee decides to develop and calculations to
incur costs to bring a field into production reflect industry
concerns that our
determinations may
not always coincide
with industry
decisions, even
using the same
input data. If,
under these altered
conditions, the
dual test indicates
that no amount of
royalty relief will
make the field
economic, we can
reasonably infer
that the
application is
missing some key
factor in the
decision to
develop.
203.68/Review and Evaluation--Dual Because sunk costs aren't in the dual test, it doesn't The difference in
Test Treatment of Sunk Costs. prove development is economic without royalty when the way the two
compared to the way the primary test defines economic tests
``economic-ness.'' Treat sunk costs the same in both treat sunk costs
tests and include them in the volume determination. favors the
Chance of relief is lost in a redetermination by applicant. Omission
defining all of the expended development costs as of sunk costs from
sunk the dual test
raises the net
present value
(NPV), improving
chances for passing
that part of the
viability test.
Their inclusion in
the primary test
has the opposite
effect on NPV,
again improving
chances for passing
that part of the
viability test. As
for volume
determinations, the
DWRRA directs us to
consider sunk costs
in determining
eligibility for
relief but not in
setting a volume
suspension to
recover them.
Finally, there is
no difference in
the treatment of
sunk costs in the
original
application and
redetermination.
The only difference
is in timing, i.e.,
more development
costs may have been
expended and hence
treated as sunk at
time of re-
submission. That
will raise the NPV
in the dual test
more than it will
raise the NPV in
the primary test,
expanding the range
of qualifying
values.
[[Page 2611]]
203.70 & 91/Review and Evaluation-- Full development cost is seldom known before first We agree that a
Post-production development production, so a pre-production report would come review before
report. before all wells would be drilled. Drilling costs are production starts
significant, often around 50 percent. Keep self- may be premature.
disclosure to encourage efficiency and reduce audit The rules require
requirements but have an updated estimate of the start-of-
development costs provided before the first production cost
anniversary of start of production. report within 60
days after
production begins.
We may grant short
extensions for
extenuating
circumstances. This
gives applicants
time to compile
data on
expenditures up to
a well-defined
point and avoids
the ambiguity
surrounding the
actual start date
and the need to
estimate some cost
items.
203.70, 76 & 90/Change in Material What constitutes start of construction or fabrication? The revised rule
Fact--Start of Construction. stipulates the
following
requirements to
verify when
construction
starts: (1) a copy
of the contract
with the
fabrication yard,
(2) a letter from
the contractor
certifying that
construction has
started on a
specific system for
a specific
location, and (3)
evidence of a
payment of
appropriate size
based on current
industry standards
for the proposed
development and
production system.
203.71/Applying Suspension Can a higher minimum suspension volume apply if the No. Minimum
Volumes--Adding leases to a field. MMS evaluation of the application includes potential suspension volumes
resources on unleased blocks and or leases not are based on the
currently assigned to the field? deepest lease
assigned to the
field up to the
time the
application is
approved. Of
course, we can
still grant larger
amounts of relief
than the minimum
suspension volumes,
if we find them
necessary to make
the whole field
economic.
203.73/Applying Suspension The fixed conversion factor ignores fluctuations in The oil/gas ratio
Volumes--Gas-to-Oil Conversion the relative values of oil and gas and introduces will continue to be
Factor. bias as it overvalues gas relative to oil properties based on the
at current value ratios. The 8-to-1 ratio implied in British thermal
the DWRRA may be better than the 5.62-to-1 ratio in unit (Btu)
the interim rule conversion factor.
Because the RSVP
model values oil
and gas separately,
the conversion
ratio affects only
the size of the
volume suspension,
not qualification
for relief.
Qualified
applicants already
get minimum volumes
under the DWRRA
even if only small
volume suspensions
are needed. These
minimum stipulated
volumes were based
on our studies
using the Btu
ratio. Hence, it
would be
inconsistent to
have the volume
suspension amounts
based on relative
prices when the
minimum volumes
were based on
studies using the
Btu ratio.
203.74/Redeterminations-- Conditions for redeterminations should include We often can't
Reprocessed Seismic Data. reprocessed seismic data (using new algorithms). This distinguish a new
differs from reinterpreting existing data, which is algorithm from a
explicitly excluded as a basis for redetermination reinterpretation of
an old one, so
we'll limit this
requirement to new
data developed by
the applicant as a
basis for a
redetermination.
203.74/Redeterminations--Price A decline of 25 percent in oil or gas price is much Sharp price swings
Change Size. too low to trigger a redetermination. Cash flow is are often short-run
very sensitive to price and a 10 percent drop in phenomena not
price can be enough to trigger a redetermination matched by changes
in forecasts of
long-term price
trends used in a
redetermination.
Also price/cost
differences, not
just prices, drive
cash flow. Some
cost-cutting
inevitably
accompanies price
declines. Only
sustained, sizeable
price declines,
such as 25 percent,
are likely to
overwhelm cost-
cutting
opportunities
enough to warrant a
redetermination.
203.74/Redeterminations--Price What is the relevant price which must drop by 25 Applicants may seek
Base. percent to qualify an applicant for a a redetermination
redetermination? if a weighted 12-
month moving
average of daily
closing New York
Mercantile Exchange
(NYMEX) prices for
oil or gas has
decreased by more
than 25 percent
since the most
recent complete
application. As the
revised rule
explains, the
before and after
prices are weighted
using the volumes
of oil and gas
identified in the
most likely
scenario described
in that
application.
Deep Water Guidelines The minimum oil price of $16.30 per barrel and the Starting price
Supplementing 203.74/ average annual growth rate of 1.67 percent is too assumptions are
Redeterminations--Price high for the next 25 years based on Energy
Assumptions. Information
Administration
(EIA) historical
data and growth
rates in EIA's
Annual Energy
Outlook and will be
updated regularly.
To match the GOM
market better,
we'll use recent
prices for
Petroleum
Administration for
Defense District
(PADD) III imports
as a benchmark for
starting prices.
Adjustments for
gravity differences
are allowed. As
with all
projections,
experience may
prove starting
prices
representative or
not and growth
rates right or
wrong. But
applicants will be
on an equal footing
because we mandate
specific
parameters.
Deep Water Guidelines The guidelines aren't consistent with the interim rule Agree. We have
Supplementing 203.76/Changes in language and preamble discussion regarding ``material changed the
Material Fact--Limits. change.'' guidelines to be
consistent with the
rule. In
particular, the
four circumstances
(change of system,
excess delay in
starting,
underspending on
development, or
false statements/
omitted reports)
used to signify a
material change are
the only ones--not
just examples--of
what justifies
withdrawal of
already granted
relief.
[[Page 2612]]
203.76 & 87-89/Changes in Material MMS doesn't need three development scenarios to test The withdrawal
Fact & Engineering, Production, viability because the section on withdrawing approval conditions focus on
and Cost reports--Multiple for royalty relief protects against significant underspending
Development Scenarios. changes development costs
and changes in
development systems
evaluated in the
application. They
don't consider
adjustments to
planned capacity
before or after
production begins.
We consider up to
three scenarios to
reflect uncertainty
about final project
size, timing, and
production rates.
We have clarified
the options for
simplifying the
input data.
Generally, whenever
observed conditions
or formal decisions
foreclose some or
all the uncertainty
about particular
variables, we
accept fewer
scenarios or point
estimates for
reservoirs, costs,
and production.
203.76/Change in Material Fact-- Conversion of proposed development costs to sunk costs Agree. We'll allow
Reapplication with Sunk in a reapplication compounds the penalty from applicants to
Development Costs. withdrawal. The reapplication is allowed less cost renounce relief at
with which to justify relief any point after
approval is granted
and before
production starts.
When violation of a
withdrawal
condition is
anticipated, giving
up relief early can
reduce the share of
development costs
that get considered
as sunk costs in a
subsequent
application.
Deep Water Guidelines What expenditures are included in development costs? We'll count all
Supplementing 203.76 & 89/Change eligible expenses
in Material Fact--Defining planned for the
Development Cost. most likely
scenario between
application and
start of
production. The
spending threshold
and any disallowed
costs (for
uneconomic
reservoirs) will be
specified in the
relief approval. In
assessing the
economic viability
of the subject
field, we may
remove the cash
flows associated
with uneconomic
reservoirs.
Deep Water Guidelines What happens if the development period (i.e., time to We'll compare actual
Supplementing 203.76/Change in first production) deviates from an applicant's to approved pre-
Material Fact--Development Period. proposal? production costs,
regardless of how
much or little time
it takes to start
production.
203.76/Only ``Significant'' Change Withdrawal as a result of actual cost below 80 percent Withdrawal
in Material Fact before (or 90 percent for redetermination that follows conditions need to
Withdrawal of Approved Relief. withdrawal of previously granted relief) of be fixed and
application estimates discourages capital efficiency. obvious, not
Also a 10 to 20 percent cost reduction may not flexible
greatly improve project economics. MMS should combinations to be
withdraw relief only if reduction in capital costs determined later.
``substantially'' improve project economics beyond We've taken three
those on which the project qualified. Even if such a steps to soften the
change occurs, the applicant ought to be allowed to danger of a fixed
appeal to keep relief so as not to encourage threshold. First,
inefficient expenditures the applicant may
keep one-half of
the relief if we're
notified of the
shortfall. Second,
the withdrawal date
is now after
production begins.
Third, the pre-
production period
is variable, so we
count an
applicant's costs
over a flexible
interval. As a
result, it's
unlikely that the
company would
substantially
underspend its
earlier capital
cost projections by
the time of review.
203.78/Applying Suspension Will a market gas price increase that is not No. The statute
Volumes--Price Ceilings on accompanied by a rise in oil price trigger a lifting doesn't explicitly
Different Products. of all the royalty-suspension volume for a field with answer this
mostly oil reserves or vice versa? question. We've
interpreted the
applicable text to
mean that price
ceilings prescribed
in the law for
lifting relief
should apply
separately to each
product for fields
that produce both.
Relief can be
suspended on just
the part of total
production from a
field whose price
exceeded the
threshold. Gas
prices above $3.50
per million Btus
(escalated to then-
current dollars)
won't lift relief
on oil volumes if
oil prices remain
below $28 per
barrel (escalated
to then-current
dollars) and vice
versa. Escalation
by the Gross
Domestic Price
deflator raises the
thresholds each
year.
203.78/Applying Suspension A time limit should be set for MMS to make royalty Agree. The new
Volumes--Time Limits for Royalty refunds or credits, as are set for companies to repay Royalty
Refunds or Credits. back royalties with interest, under the price Simplification and
escalation clause Fairness Act
requires that MMS
process refunds or
credits on
production after
September 1996
within 120 days of
a lessee's request.
Future rules will
set forth
procedures which
deal with this
request. The
repayment period
for companies is
also set at 120
days.
----------------------------------------------------------------------------------------------------------------
Comments on the Required Reports
----------------------------------------------------------------------------------------------------------------
Requirement/Subject Comment MMS Response
----------------------------------------------------------------------------------------------------------------
203.81/Independent Certification.. A certified public accountant (CPA) certification of A CPA certification
historical expenditures reported in either the is an independent
application or the pre-production report imposes check and so might
unnecessary costs. Internal records and self substitute for our
certification are adequate audit. Besides,
only eligible
expenditures must
be certified.
However, to reduce
the cost of the
independent audit,
we will accept a
CPA opinion which
identifies
questionable
elements or an
unqualified opinion
on the accuracy and
relevance of the
historical
information
presented.
[[Page 2613]]
Deep Water Guidelines What is a CPA certification for sunk costs? It's a CPA report
Supplementing 203.81/ that certifies your
Certification Format. historical
information is
accurate and meets
our stipulations on
eligibility. As the
revised guidelines
state, an agent of
the CPA firm must
sign the
certification and
identify someone
who knows the case
and is authorized
to respond to
questions on it.
203.83/Administrative report-- Requiring certification that reserves won't be Agree. We've
Certification of Non-Development. produced without relief is not enforceable and can be eliminated this
outdated as conditions change requirement.
Considering sunk
costs in the
evaluation means
that some fields
that qualify for
relief would be
worth developing
without relief.
203.85/Economic viability report-- The spreadsheet model should allow for cost inflation Future versions of
Inflation. the spreadsheet
model may include a
variable to account
for cost-specific
inflation or
deflation.
Technological
progress could
actually lower real
costs over time
despite general
inflation of all
prices and costs.
203.85/Economic viability report-- MMS should fix a schedule for revising price Agree. We'll publish
Updating Price Assumptions assumptions (e.g., quarterly, annually). If MMS updated price
Schedule. issues new assumptions while reviewing an assumptions on the
application, they should clarify which assumptions INTERNET annually,
apply (those at time of application or latest issued probably in the
before the determination) late spring when
EIA's Annual Energy
Outlook releases
new data and
forecasts. We'll
use the price
assumptions in
place on the date
of application
submission.
203.85/Economic viability report-- Will MMS accept the discount rate an applicant We'll use the
Revising Applicants' Assumptions- selects, or reserve the right to revise the discount discount rate an
Discount Rates. rate? applicant proposes
in both the dual
and primary tests,
with no
appropriateness
review as long as
it is within the
range provided in
the guidelines.
203.85/Economic viability report-- The 10 percent discount rate is too low. Even 15 In all cases, the
Discount Rate Size. percent is too low because it risks rejected projects rates of return
being abandoned apply to a field
with a discovery,
so the risk of not
finding oil or gas
is gone. The range
specified in the
guidelines for the
discount rate is
based on recent
historical
experience, which
in future years may
assume a different
trend. The
industry's average
after-tax, real
rate of return, has
been estimated to
range from a high
of 10.9 percent to
a low of 1.4
percent between
1959 and 1988. (See
A.T. Guernsey on
behalf of Shell Oil
Company,
Profitability
Study: Crude Oil
and Natural Gas
Exploration,
Development, and
Production
Activities in the
USA, 1959-1988,
November 1990).
Simulations with a
version of our
model found before-
tax rates of return
ranged from 1.2 to
4 percent higher
than after-tax
rates of return
over various
project conditions.
Together, these
estimates indicate
that expecting
before-tax discount
rates, and hence
rates of return, in
the range of 10 to
15 percent are
appropriate.
203.85/Economic viability report-- Allowing variability in discount rates could lead to The goal of a range
Discount Rate Range. unequal treatment. Where applicants choose discount of discount rates
rates, the playing field isn't level. Instead, is to fit
specify one for each of three water-depth thresholds differences in
and apply uniformly companies' risk
tolerance and
opportunity cost.
Applicants can
tailor their risk
preferences by
water depth within
this range if they
choose to. We use
probability methods
that don't require
a risk premium in
the discount rate.
However, a fixed
discount rate
across fields and
companies within a
water-depth
category places all
the burden for
dealing with
differences in risk
on these
probability
distributions. We
believe a better
compromise is to
give applicants the
chance to use both
factors to express
their risks and
uncertainties.
Allowing companies
to choose a rate
for their projects
is eminently fair,
as long as they
stay within our
stipulated range
and we use it in
both economic
viability tests.
203.89/Cost report--Sunk Costs The way MMS includes sunk costs doesn't recognize the The DWRRA directs us
Measurement. time value of money, as past expenditures are carried to consider all
forward without escalation. It's inappropriate to exploration,
combine after-tax sunk costs with future costs and development, and
revenues expressed on a before-tax basis production costs.
Because the
decision to proceed
on a project is
independent of sunk
costs, the proper
treatment of sunk
costs for economic
viability is to
value them as zero.
We balance these
considerations by
carefully defining
expenses that
constitute sunk
costs, then we
allow them as a
deduction in the
primary test and
exclude them from
the dual test. The
after-tax part of
sunk costs, like
the before-tax size
of prospective
costs, is what the
company still has
to recover from the
proposed project.
203.89/Sunk Costs--Scope.......... Sunk costs should include all reasonable post-lease We won't consider
acquisition costs (seismic data costs, overhead sunk costs incurred
expenses, etc.). Extend the definition to include all by previous owners
project costs incurred by the lessee or on behalf of of your lease or by
a lessee third-parties.
Also, we won't
consider portions
of sunk costs on
your lease that you
incurred prior to
when you last
bought into your
lease. Further, if
you have maintained
continous ownership
but changed the
share of the lease
you own, we count
your sunk costs
only in proportion
to the share you
owned when you
incurred these
costs. We do this
because previous
owners and third-
parties already
have been
compensated through
market
transactions. Also,
we do not believe
we can really
verify the
relevance to
current development
of expenditures by
third-parties or
previous owners.
[[Page 2614]]
203.91 & 76/Review and Evaluation-- What must the post-production report contain? What The report must show
Post-production development happens if it isn't submitted? and compare planned
report. and actual pre-
production costs.
If you don't submit
the report, you'll
lose relief, just
as you would for
providing false
historical or
intentionally
inaccurate
information.
----------------------------------------------------------------------------------------------------------------
IV. Recovery of Costs
By Federal policy and law, we'll charge lessees applying for
royalty relief under this rule an amount which recovers our cost of
processing their applications. The Independent Office Appropriation Act
(31 U.S.C. 9701) and OMB Circular A-25 require agencies to 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 Omnibus Appropriations Bill (Pub. L. 104-134, 110
Stat. 1321, April 26, 1996) authorizes collecting such fees.
We issued NTL No. 96-3N (signed June 21, 1996), which gives
detailed amounts for processing royalty-relief applications and when
and how applicants may pay us. Processing applications for royalty
relief to increase production will cost $8,000. Complete applications
under DWRR will cost either $16,000 to $34,000. Draft applications will
cost either $10,500 to $28,500. For some applications, we may need to
audit the financial data submitted to determine the proposed
development's economics. That would cost up to $37,500. Ordinarily, no
refund is given when we reject an application. However, if we reject a
deep water application for incompleteness during the first 20 business
days after receiving it, we'll refund all but $5,500 of the application
fee. We'll revise the Notice to Lessees (NTL) periodically to reflect
our cost experience and to provide other information helpful or
necessary for administering this program.
Authors: Sam Fraser and Marshall Rose, Economics Division, prepared
this document.
V. Administrative Matters
Executive Order (E.O.) 12866
This rule is significant due to novel policy issues arising from
legal mandates, and OMB has reviewed this rule. We will make a copy of
our determination of the effects of this rule available on request.
In summary, the DWRRA instructs us to grant royalty relief only in
situations that are uneconomic at the lease-stipulated royalty rate.
Hence, the economic effects can be estimated by 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. MMS's field-based
approach generates up to $45 million per year in additional royalty
revenue, which is less than the threshold amount of $100 million
annually.
The field-based approach provided in this final rule gives a single
royalty-suspension volume for each qualifying field. The main
alternative approach gives each individual lease or unit a separate
royalty-suspension volume, subject to the minimum volumes specified in
the DWRRA.
We chose the field-based approach because:
The DWRRA's primary author stated that he intended the
DWRRA to encourage production from new fields without providing any
more relief than needed;
The field-based approach provides a substantial incentive
for developing marginal fields in deep water while still ensuring a
fair 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 GOM so that all deep water leases on the
OCS receive equitable treatment.
Regulatory Flexibility Act
This rule can have a positive economic effect on some small
entities. A copy of our analysis of this impact is available on
request.
In summary, this rule sets the terms and conditions for granting
royalty relief under the provisions of section 8(a)(3)(A) of the OCSLA.
These terms reduce costs for end-of-life operations by 6 to 10 percent,
more than doubling profits. That should significantly prolong
operations on marginally economic leases. We can't estimate the number
of leases that may be affected from past experience, because the terms
have been changed from those previously available to marginal OCS
leases. We estimate that small entity operators account for under 10
percent of production from OCS leases.
This rule also sets terms and conditions for granting royalty-
suspension volumes under the DWRRA for certain deep water leases on the
OCS in the GOM. These leases were issued as a result of a lease sale
held before November 28, 1995. The conditions limit these terms to the
rare situations in which royalty costs are the difference between
unprofitable and profitable development. One of two applications for
deep water relief received under the interim version of this rule was
from a small entity.
Paperwork Reduction Act
In connection with the interim final rulemaking (IFR) process, we
submitted the information collection requirements in 30 CFR 203 to OMB
and conducted a full review and comment process for this collection of
information. OMB approved the information collection (OMB No. 1010-
0071) on October 7, 1996, to expire on October 31, 1999.
Earlier in the preamble we discussed comments received on the
information collection aspects of the IFR. Based on experience and the
changes made in this rule, we will submit a revised information
collection package to OMB for approval 60 days after this rule is
published. With this rule, we are starting the 60-day comment period.
The Paperwork Reduction Act of 1995 (44 U.S.C. 3501 et seq.) provides
that an agency may not conduct or sponsor, and a person is not required
to respond to, a collection of information unless it displays a
currently valid OMB control number. The information collection aspects
of this final rule will not take effect until approved by OMB.
We invite the public and other Federal agencies to comment on the
collection of information as discussed below. Send comments regarding
any aspect of the collection to the Minerals Management Service,
Attention: Rules Processing Team, 381 Elden Street, Mail Stop 4020,
Herndon, VA 20170. Your comments should be received by March 17, 1998.
[[Page 2615]]
We use the information to determine whether royalty relief will
result in production that wouldn't otherwise occur. We rely largely on
your information to make these determinations. Your application for
royalty relief must contain enough information on finances, economics,
reservoirs, G&G characteristics, production, and engineering estimates
for us to determine whether: (1) We should grant relief under the law,
and (2) the requested relief will ultimately recover more resources and
return a reasonable profit on project investments. Your fabricator
confirmation and post-production development reports must contain
enough information for us to verify that your application reasonably
represented your plans.
Applicants (respondents) are Federal OCS oil and gas lessees.
Applications are required to obtain or retain a benefit. Therefore, if
you apply for royalty relief, you must provide this information. We
will protect information considered proprietary under applicable law
and under regulations at Sec. 203.63(b) and part 250 of this chapter.
We estimate the annual public reporting burden for this information
collection will average approximately 14,700 hours, not the 38,730
hours originally estimated for the interim final rule. The reduction is
due primarily to an adjustment in re-estimating the number of
applications we expect to receive. We also made minor program
reductions in the estimate based on the changes in the final rule. The
average burden per response is estimated at 335 burden hours. This
includes the time for reviewing instructions, searching existing data
sources, gathering and maintaining the data needed, and completing and
reviewing the collection of information. A breakdown of the estimated
burden is included in the supporting statement we submitted to OMB for
this collection of information. You may obtain a copy of that
supporting statement from MMS's Information Collection Clearance
Officer (202/208-7744). In calculating the burdens, we've assumed that
respondents perform some of the requirements and maintain records in
the normal course of their activities. We consider these to be usual
and customary. You are invited to provide information in your comments
if you disagree with this assumption.
We specifically solicit comments on the following questions:
(a) Is the proposed collection of information necessary for us to
properly perform our functions, and will it be useful?
(b) Are the burden hours estimates reasonable for the proposed
collection?
(c) Do you have any suggestions that would enhance the quality,
clarity, or usefulness of the information to be collected?
(d) Is there a way to minimize the information collection burden on
the applicants, including the use of appropriate automated electronic,
mechanical, or other forms of information technology?
In addition, the Paperwork Reduction Act requires us to estimate
the total annual cost burden to respondents or recordkeepers resulting
from the collection of information. We need your comments to identify
any reporting and recordkeeping cost burdens other than those discussed
above. Your response should split the cost estimate into two
components: (a) Total capital and startup cost component; and (b)
annual operation, maintenance, and purchase of services component. Your
estimates should consider the costs to generate, maintain, and disclose
or provide the information. You should describe the methods you use to
estimate major cost factors, including system and technology
acquisition, expected useful life of capital equipment, discount
rate(s), and the period over which you incur costs. Capital and startup
costs include, among other items, computers and software you purchase
to prepare for collecting information; monitoring, sampling, drilling,
and testing equipment; and record storage facilities. Generally, your
estimates should not include equipment or services purchased: (i)
before October 1, 1995; (ii) to comply with requirements not associated
with the information collection; (iii) for reasons other than to
provide information or keep records for the Government; or (iv) as part
of customary and usual business or private practices.
Takings Implication Assessment
DOI certifies that this rule does not represent a governmental
action that can interfere with constitutionally protected property
rights. Therefore, we don't need to do a Takings Implication Assessment
under E.O. 12630, Governmental Actions and Interference with
Constitutionally Protected Property Rights.
E.O. 12988
DOI has certified to OMB that the rule meets the applicable reform
standards provided in sections 3(a) and 3(b)(2) of E.O. 12988.
National Environmental Policy Act
DOI has determined that this rule isn't a major Federal action that
significantly affects the quality of the human environment, so we don't
need an Environmental Impact Statement.
Unfunded Mandates Reform Act of 1995
DOI has determined and certifies according to the Unfunded Mandates
Reform Act, 2 U.S.C. 1502 et seq., that this rule will not impose a
cost of $100 million or more in any given year on State, local, and
tribal governments or the private sector.
``Plain English'' Style of Writing
We've written this regulation in the form of questions in the first
person (I) and answers in the second person (you) because readers may
find it simpler to read and understand. A question and its answer
combine to establish a rule. The applicant and the agency must follow
the language in the question and its answer.
List of Subjects in 30 CFR Part 203
Continental shelf, Government contracts, Indians-lands, Minerals
Royalties, Oil and gas exploration, Public lands-mineral resources,
Sulphur.
Dated: November 6, 1997.
Bob Armstrong,
Assistant Secretary, Land and Minerals Management.
For the reasons stated 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 et
seq.; 43 U.S.C. 1301 et seq.; 43 U.S.C. 1331 et seq.; and 43 U.S.C.
1801 et seq.
2. Subpart A is revised to read as follows:
Subpart A--General Provisions
Sec.
203.0 What definitions apply to this part?
203.1 What is MMS's authority to grant royalty relief?
203.2 When can I get royalty relief?
203.3 Why must I pay a fee to request royalty relief?
203.4 How do the provisions in this part apply to different types
of leases and projects?
[[Page 2616]]
Subpart A--General Requirements
Sec. 203.0 What definitions apply to this part?
Authorized field means a field in a water depth of at least 200
meters and in the Gulf of Mexico west of 87 degrees, 30 minutes West
longitude from which no current pre-Act lease produced, other than test
production, before November 28, 1995.
Complete application means an original and two copies of the six
reports consisting of the data specified in 30 CFR 203.81, 203.83 and
203.85 through 203.89, along with one set of digital information, which
MMS has reviewed and found complete.
Determination means the binding decision by MMS on whether your
field qualifies for relief or how large a royalty-suspension volume
must be to make the field economically viable.
Draft application means the preliminary set of information and
assumptions you submit to seek a nonbinding assessment on whether a
field could be expected to qualify for royalty relief.
Eligible lease means a lease that results from a lease sale held
after November 28, 1995; is located in the Gulf of Mexico (GOM) in
water depths 200 meters or deeper; lies wholly west of 87 degrees, 30
minutes West longitude; and is offered subject to a royalty-suspension
volume authorized by statute.
Expansion project means a project you propose in a Development
Operations Coordination Document (DOCD) or a Supplement approved by the
Secretary of the Interior after November 28, 1995, that will increase
the ultimate recovery of resources from a pre-Act lease and that
involves a substantial capital investment (e.g., fixed-leg platform,
subsea template and manifold, tension-leg platform, multiple well
project, etc.).
Fabrication (or start of construction) means evidence of
irreversible commitment to a concept and scale of development,
including copies of a binding contract between you (as applicant) and a
fabrication yard, a letter from a fabricator certifying that
construction has begun, and a receipt for the customary down payment.
Field means an area consisting of a single reservoir or multiple
reservoirs all grouped on, or related to, the same general geological
structural feature or stratigraphic trapping condition. Two or more
reservoirs may be in a field, separated vertically by intervening
impervious strata or laterally by local geologic barriers, or both.
Lease means a lease or unit.
New production means any production from a current pre-Act lease
from which no royalties are due on production, other than test
production, before November 28, 1995. Also, it means any production
resulting from lease-development activities involving a substantial
capital investment (e.g., fixed-leg platform, subsea template and
manifold, tension-leg platform, multiple well project, etc.) on a
current pre-Act lease under a Development Operations Coordination
Document--or its supplement--approved by the Secretary of the Interior
after November, 28, 1995.
Nonbinding assessment means an opinion by MMS of whether your field
could qualify for royalty relief. It is based on your draft application
and does not entitle the field to relief.
Performance conditions means minimum conditions you must meet,
after we have granted relief and before production begins, to remain
qualified for that relief. If you do not meet each one of these
performance conditions, we consider it a change in material fact
significant enough to invalidate our original evaluation and approval.
Pre-Act lease means a lease issued as a result of a lease sale held
before November 28, 1995; in a water depth of at least 200 meters; and
in the Gulf of Mexico west of 87 degrees, 30 minutes West longitude.
Production means all oil, gas, and other relevant products you
save, remove, or sell from a tract or those quantities allocated to
your tract under a unitization formula, as measured for the purposes of
determining the amount of royalty payable to the United States.
Project means any activity that requires at least a permit to
drill.
Redetermination means your request for us to reconsider our
determination on royalty relief if we have rejected your application or
if we have granted relief but you want a larger suspension volume.
Renounce means action you take to give up relief after we have
granted it and before you start production.
Sunk costs means costs (as specified in 30 CFR 203.89(a)) of
exploration, development, and production that you incur after the date
of first discovery on the field and before the date we receive your
complete application for royalty relief. Sunk costs include the costs
of the discovery well qualified as producible under 30 CFR part 250,
subpart A but do not include any pre-discovery activity costs or lease
acquisition and holding costs such as cash bonus and rental payments.
Withdraw means action we take on a field that has qualified for
relief if you have not met one or more of the performance conditions.
Sec. 203.1 What is MMS's authority to grant royalty relief?
The Outer Continental Shelf (OCS) Lands Act, 43 U.S.C. 1337, as
amended by the OCS Deep Water Royalty Relief Act (DWRRA), Public Law
104-58, authorizes us to grant royalty relief in three situations.
(a) Under 43 U.S.C. 1337(a)(3)(A), we may reduce or eliminate any
royalty or a net profit share specified for an OCS lease to promote
increased production.
(b) Under 43 U.S.C. 1337(a)(3)(B), we may reduce, modify, or
eliminate any royalty or net profit share to promote development,
increase production, or encourage production of marginal resources on
certain leases or categories of leases. This authority is restricted to
leases in the Gulf of Mexico (GOM) that are west of 87 degrees, 30
minutes West longitude.
(c) Under 43 U.S.C. 1337(a)(3)(C), we may suspend royalties for
designated volumes of new production from any lease if:
(1) Your lease is in deep water (water at least 200 meters deep);
(2) Your lease is in designated areas of the GOM (west of 87
degrees, 30 minutes West longitude);
(3) Your lease was acquired in a lease sale held before the DWRRA
(before November 28, 1995);
(4) We find that your new production would not be economic without
royalty relief; and
(5) Your lease is on a field that did not produce before enactment
of the DWRRA, or if you propose a project to significantly expand
production under a Development Operations Coordination Document (DOCD)
or a supplementary DOCD, that MMS approved after November 28, 1995.
Sec. 203.2 When can I get royalty relief?
We can reduce or suspend royalties for OCS leases or projects that
meet the criteria in the following table.
[[Page 2617]]
------------------------------------------------------------------------
THEN YOU MAY BE
IF YOU HAVE A LEASE-- AND IF YOU-- GRANTED--
------------------------------------------------------------------------
That generates earnings Seek to increase A reduced royalty
which cannot sustain production by rate on current
production (End-of-Life operating the lease production flows
lease),. beyond the point at along with a higher
which it is royalty rate on
economic under the some additional
existing royalty production flows.
rate,.
In designated areas of the Are producing and A royalty suspension
deep water GOM, acquired in seek to increase for an increment to
a lease sale held before ultimate recovery production large
November 28, 1995, and you of resources from enough to make the
propose activity in a DOCD the field with a project economic.
or supplement to substantial
significantly expand investment (e.g.,
production,. platform, multiple
wells, subsea
template) (an
expansion project),.
In designated areas of the Are on a field from A royalty suspension
deep water GOM, acquired in which no current for a minimum
a lease sale held before pre-Act lease production volume
November 28, 1995 (pre-Act produced (other plus any additional
lease),. than test volume needed to
production) before make the field
November 28, 1995 economic.
(authorized field),.
------------------------------------------------------------------------
Sec. 203.3 Why must I pay a fee to request royalty relief?
(a) When you submit an application or ask for a preview assessment,
you must include a fee to reimburse us for our costs of processing your
application or assessment. Federal policy and law require us to recover
the cost of services that confer special benefits to identifiable non-
Federal recipients. The Independent Offices Appropriation Act (31
U.S.C. 9701), Office of Management and Budget Circular A-25, and the
Omnibus Appropriations Bill (Pub. L. 104-133, 110 Stat. 1321, April 26,
1996) authorize us to collect these fees.
(b) We will specify the necessary fees for each of the types of
royalty-relief applications and possible MMS audits in a Notice to
Lessees. We will periodically update the fees to reflect changes in
costs as well as provide other information necessary to administer
royalty relief.
Sec. 203.4 How do the provisions in this part apply to different types
of leases and projects?
The tables in this section summarize how similar provisions in this
part apply in different situations.
(a) Provisions relating to application content in Secs. 203.51,
203.62 and 203.81 through 203.89.
----------------------------------------------------------------------------------------------------------------
Deep water
Information elements End-of-life expansion Pre-act deep
lease project water lease
----------------------------------------------------------------------------------------------------------------
Administrative information report............................ x x x
Net revenue and relief justification report (prescribed
format)..................................................... x
Economic viability and relief justification report (Royalty
Suspension Viability Program (RSVP) model inputs justified
with Geological & Geophysical (G&G), Engineering,
Production, & Cost reports)................................. ............... x x
G&G report................................................... ............... x x
Engineering report........................................... ............... x x
Production report............................................ ............... x x
Deep Water cost report....................................... ............... x x
----------------------------------------------------------------------------------------------------------------
(b) Provisions relating to verification in Secs. 203.70, 203.81 and
203.90 through 203.91.
----------------------------------------------------------------------------------------------------------------
Deep water
Confirmation elements End-of-life expansion Pre-act deep
lease project water lease
----------------------------------------------------------------------------------------------------------------
Fabricator's confirmation report............................. ............... x x
Post-production development report (approved by certified
public accountant (CPA)..................................... ............... x x
----------------------------------------------------------------------------------------------------------------
(c) Provisions relating to approval criteria contained in
Secs. 203.50, 203.52, 203.60 and 203.67.
----------------------------------------------------------------------------------------------------------------
Deep water
Approval conditions End-of-life expansion Pre-act deep
lease project water lease
----------------------------------------------------------------------------------------------------------------
At least 12 of the last 15 months have the required level of
production.................................................. x
Already producing............................................ x x
Well can produce............................................. ............... ............... x
Royalties for qualifying months exceed 75 percent of net
revenue (NR)................................................ x
Substantial investment (e.g., platform, multiple wells,
subsea template)............................................ ............... x
Determined to be economic only with relief................... ............... x x
----------------------------------------------------------------------------------------------------------------
(d) Provisions related to redetermination in Secs. 203.52 and
203.74 through 203.75.
----------------------------------------------------------------------------------------------------------------
Deep water
Redetermination conditions End-of-life expansion Pre-act deep
lease project water lease
----------------------------------------------------------------------------------------------------------------
After 12 months under current rate, criteria same as for
approval.................................................... x
For material change in geologic data, prices, or costs....... ............... x x
----------------------------------------------------------------------------------------------------------------
[[Page 2618]]
(e) Provisions related to the format of relief in Secs. 203.53 and
203.69.
----------------------------------------------------------------------------------------------------------------
Deep water
Relief rate & volume End-of-life expansion Pre-act deep
lease project water lease
----------------------------------------------------------------------------------------------------------------
One-half pre-application effective lease rate on the
qualifying amount, 1.5 times pre-application effective lease
rate on additional production up to twice the qualifying
amount, and the pre-application effective lease rate for any
larger volumes.............................................. x
Qualifying amount is the average monthly production for 12
qualifying months........................................... x
Zero royalty rate on the suspension volume and the original
lease rate on additional production......................... x x
Field Suspension volume is at least 17.5, 52.5 or 87.5
million barrels of oil equivalent (MMBOE)................... x
Amount needed to become economic............................. x x
----------------------------------------------------------------------------------------------------------------
(f) Provisions related to discontinuing relief Secs. 203.54 and
203.78.
----------------------------------------------------------------------------------------------------------------
Deep water
Full royalty resumes when-- End-of-life expansion Pre-act deep
lease project water lease
----------------------------------------------------------------------------------------------------------------
Average NYMEX price for last 12 months is at least 25 percent
above the average for the qualifying months................. x
Average NYMEX price for last 12 months exceeds $28/bbl or
$3.50/mcf, escalated by the gross domestic product deflator
since 1994.................................................. x x
----------------------------------------------------------------------------------------------------------------
(g) Provisions related to the end, loss or reduction of relief in
Secs. 203.55 and 203.76.
----------------------------------------------------------------------------------------------------------------
Deep water
Relief withdrawn or reduced End-of-life expansion Pre-act deep
lease project water lease
----------------------------------------------------------------------------------------------------------------
Recipient so requests........................................ x
Lease rate is at the effective rate for 12 consecutive months x
Conditions that we may specify in the approval letter in
individual cases actually occur............................. x
Not submitting post-production report that compares expected
to actual costs............................................. x x
Change of development system................................. x x
Excess delay in starting fabrication......................... x x
Spending less than 80 percent of proposed pre-production
costs but notifying us in post-production report............ x x
Amount of relief volume is produced.......................... x x
----------------------------------------------------------------------------------------------------------------
3. Subpart B is revised to read as follows:
Subpart B--OCS Oil, Gas, and Sulfur General
Royalty Relief for end-of-life Leases
Sec.
203.50 Who may apply for end-of-life royalty relief?
203.51 How do I apply for end-of-life royalty relief?
203.52 What criteria must I meet to get relief?
203.53 What relief will MMS grant?
203.54 How does my relief arrangement for an oil and gas lease
operate if prices rise sharply?
203.55 Under what conditions can my end-of-life royalty relief
arrangement for an oil and gas lease be ended?
203.56 Does relief transfer when a lease is assigned?
Royalty Relief For Deep Water Expansion Projects And Pre-Act Deep Water
Leases
203.60 Who may apply for deep water royalty relief?
203.61 How do I assess my chances for getting relief?
203.62 How do I apply for relief?
203.63 Does my application have to include all leases in the field?
203.64 How many applications may I file on a field?
203.65 How long will MMS take to evaluate my application?
203.66 What happens if MMS does not act in the time allowed under
Sec. 203.65, including any extensions?
203.67 What economic criteria must I meet to get royalty relief on
an authorized field or expansion project?
203.68 What pre-application costs will MMS consider in determining
economic viability?
203.69 If my application is approved, what royalty relief will I
receive?
203.70 What information must I provide after MMS approves relief?
203.71 How does MMS allocate a field's suspension volume between my
lease and other leases on my field?
203.72 Can my lease receive more than one suspension volume?
203.73 How do suspension volumes apply to natural gas?
203.74 When will MMS reconsider its determination?
203.75 What risk do I run if I request a redetermination?
203.76 When might MMS withdraw or reduce the approved size of my
relief?
203.77 May I voluntarily give up relief if conditions change?
203.78 Do I keep relief if prices rise significantly?
203.79 How do I appeal MMS's decisions related to Deep Water
Royalty Relief?
Required Reports
203.81 What supplemental reports do royalty-relief applications
require?
[[Page 2619]]
203.82 What is MMS's authority to collect this information?
203.83 What is in an administrative information report?
203.84 What is in a net revenue and relief justification report?
203.85 What is in an economic viability and relief justification
report?
203.86 What is in a G&G report?
203.87 What is in an engineering report?
203.88 What is in a production report?
203.89 What is in a deep water cost report?
203.90 What is in a fabricator's confirmation report?
203.91 What is in a post-production development report?
Subpart B-OLS Oil, Gas, and Sulfur General
Royalty Relief for End-of-life Leases
Sec. 203.50 Who may apply for end-of-life royalty relief?
You may apply for royalty relief in two situations.
(a) Your end-of-life lease (as defined in Sec. 203.2) is an oil and
gas lease and has average daily production of at least 100 barrels of
oil equivalent (BOE) per month (as calculated in Sec. 203.73) in at
least 12 of the past 15 months. The most recent of these 12 months are
considered the qualifying months.
(b) Your end-of-life lease is other than an oil and gas lease
(e.g., sulphur) and has production in at least 12 of the past 15
months. The most recent of these 12 months are considered the
qualifying months.
Sec. 203.51 How do I apply for end-of-life royalty relief?
You must submit a complete application and the required fee to the
appropriate MMS Regional Director. Your MMS regional office will
provide specific guidance on the report formats. A complete application
for relief includes:
(a) An administrative information report (specified in Sec. 203.83)
and
(b) A net revenue and relief justification report (specified in
Sec. 203.84).
Sec. 203.52 What criteria must I meet to get relief?
(a) To qualify for relief, you must demonstrate that the sum of
royalty payments over the 12 qualifying months exceeds 75 percent of
the sum of net revenues (before-royalty revenues minus allowable costs,
as defined in Sec. 203.84).
(b) To re-qualify for relief, e.g., either applying for additional
relief on top of relief already granted, or applying for relief
sometime after your earlier agreement terminated, you must demonstrate
that:
(1) You have met the criterion listed in paragraph (a) of this
section, and
(2) The 12 required qualifying months of operation have occurred
under the current royalty arrangement.
Sec. 203.53 What relief will MMS grant?
(a) If we approve your application and you meet certain conditions,
we will reduce the pre-application effective royalty rate by one-half
on production up to the relief volume amount. If you produce more than
the relief volume amount:
(1) We will impose a royalty rate equal to 1.5 times the effective
royalty rate on your additional production up to twice the relief
volume amount; and
(2) We will impose a royalty rate equal to the effective rate on
all production greater than twice the relief volume amount.
(b) Regardless of the level of production or prices (see
Sec. 203.54), royalty payments due under end-of-life relief will not
exceed the royalty obligations that would have been due at the
effective royalty rate.
(1) The effective royalty rate is the average lease rate paid on
production during the 12 qualifying months.
(2) The relief volume amount is the average monthly BOE production
for the 12 qualifying months.
Sec. 203.54 How does my relief arrangement for an oil and gas lease
operate if prices rise sharply?
In those months when your current reference price rises by at least
25 percent above your base reference price, you must pay the effective
royalty rate on all monthly production.
(a) Your current reference price is a weighted average of daily
closing prices on the NYMEX for light sweet crude oil and natural gas
over the most recent full 12 calendar months;
(b) Your base reference price is a weighted average of daily
closing prices on the NYMEX for light sweet crude oil and natural gas
during the qualifying months; and
(c) Your weighting factors are the proportions of your total
production volume (in BOE) provided by oil and gas during the
qualifying months.
Sec. 203.55 Under what conditions can my end-of-life royalty relief
arrangement for an oil and gas lease be ended?
(a) If you have an end-of-life royalty relief arrangement, you may
renounce it at any time. The lease rate will return to the effective
rate during the qualifying period in the first full month following our
receipt of your renouncement of the relief arrangement.
(b) If you pay the effective lease rate for 12 consecutive months,
we will terminate your relief. The lease rate will return to the
effective rate in the first full month following this termination.
(c) We may stipulate in the letter of approval for individual cases
certain events that would cause us to terminate relief because they are
inconsistent with an end-of-life situation.
Sec. 203.56 Does relief transfer when a lease is assigned?
Yes. Royalty relief is based on the lease circumstances, not
ownership. It transfers upon lease assignment.
Royalty Relief For Deep Water Expansion Projects And Pre-Act Deep
Water Leases
Sec. 203.60 Who may apply for deep water royalty relief?
Under conditions in Secs. 203.61(b) and 203.62, you may apply for
royalty relief if:
(a) You are a lessee of a lease in water at least 200 meters deep
in the GOM and lying wholly west of 87 degrees, 30 minutes West
longitude;
(b) We have assigned your lease to a field (as defined in
Sec. 203.0); and
(c) You hold a pre-Act lease on an authorized field (as defined in
Sec. 203.0) or you propose an expansion project (as defined in
Sec. 203.0).
Sec. 203.61 How do I assess my chances for getting relief?
You may ask for a nonbinding assessment (a formal opinion on
whether a field would qualify for royalty relief) before turning in
your first complete application on an authorized field. This field must
have a qualifying well under 30 CFR part 250, subpart A, or be on a
lease that has allocated production under an approved unit agreement.
(a) To request a nonbinding assessment, you must:
(1) Submit a draft application in the format and detail specified
in guidance from the MMS regional office for the GOM;
(2) Propose to drill at least one more appraisal well if you get a
favorable assessment; and
(3) Pay a fee under Sec. 203.3.
(b) You must wait at least 90 days after receiving our assessment
to apply for relief under Sec. 203.62.
(c) This assessment is not binding because a complete application
may contain more accurate information that does not support our
original
[[Page 2620]]
assessment. It will help you decide whether your proposed inputs for
evaluating economic viability and your supporting data and assumptions
are adequate.
Sec. 203.62 How do I apply for relief?
You must send a complete application and the required fee to the
MMS GOM Regional Director.
(a) Your application for deep water royalty relief must include an
original and two copies (one set of digital information) of:
(1) Administrative information report;
(2) Deep water economic viability and relief justification report;
(3) G&G report;
(4) Engineering report;
(5) Production report; and
(6) Deep water cost report.
(b) Section 203.82 explains why we are authorized to require these
reports.
(c) Sections 203.81, 203.83, and 203.85 through 203.89 describe
what these reports must include. The MMS GOM Regional Office will guide
you on the format for the required reports.
Sec. 203.63 Does my application have to include all leases in the
field?
For authorized fields, we will accept only one joint application
for all leases that are part of the designated field on the date of
application, except as provided in paragraph (c) of this section and
Sec. 203.64.
(a) The Regional Director maintains a Field Names Master List with
updates of all leases in each designated field.
(b) To avoid sharing proprietary data with other lessees on the
field, you may submit your proprietary G&G report separately from the
rest of your application. Your application is not complete until we
receive all the required information for each lease on the field. We
will not disclose proprietary data when explaining our assumptions and
reasons for our determinations under Sec. 203.67.
(c) We will not require a joint application if you show good cause
and honest effort to get all lessees in the field to participate. If
you must exclude a lease from your application because its lessee will
not participate, that lease is ineligible for the royalty relief for
the designated field.
Sec. 203.64 How many applications may I file on a field?
You may file one complete application for royalty relief during the
life of the field. However, you may send another application if:
(a) You are eligible to apply for a redetermination under
Sec. 203.74;
(b) You apply for royalty relief for an expansion project;
(c) You withdraw the application before we make a determination; or
(d) You apply for end-of-life royalty relief.
Sec. 203.65 How long will MMS take to evaluate my application?
(a) We will determine within 20 working days if your application
for royalty relief is complete. If your application is incomplete, we
will explain in writing what it needs. If you withdraw a complete
application, you may reapply.
(b) We will evaluate your first application on a field within 180
days and a redetermination under Sec. 203.75 within 120 days after we
say it is complete.
(c) We may ask to extend the review period for your application
under the conditions in the following table.
----------------------------------------------------------------------------------------------------------------
If-- Then we may--
----------------------------------------------------------------------------------------------------------------
We need more records to audit sunk costs............... Ask to extend the 120-day or 180-day evaluation period.
The extension we request will equal the number of days
between when you receive our request for records and
the day we receive the records.
We cannot evaluate your application for a valid reason, Add another 30 days. We may add more than 30 days, but
such as missing vital information or inconsistent or only if you agree.
inconclusive supporting data.
We need more data, explanations, or revision........... Ask to extend the 120-day or 180-day evaluation period.
The extension we request will equal the number of days
between when you receive our request and the day we
receive the information.
----------------------------------------------------------------------------------------------------------------
(d) We may change your assumptions under Sec. 203.62 if our
technical evaluation reveals others that are more appropriate. We may
consult with you before a final decision and will explain any changes.
(e) We will notify all designated lease operators within a field
when royalty relief is granted.
Sec. 203.66 What happens if MMS does not act in the time allowed under
Sec. 203.65, including any extensions?
If we do not act within the timeframes established in Sec. 203.65,
the conditions in the following table apply.
------------------------------------------------------------------------
And we do not decide
If you apply for royalty within the time As long as you--
relief for-- specified--
------------------------------------------------------------------------
An authorized field........... You get the minimum Abide by Secs.
suspension volumes 203.70 & 76
specified in Sec.
203.69.
An expansion project.......... You get a royalty Abide by Secs.
suspension for the 203.70 & 76
first year of
production.
------------------------------------------------------------------------
Sec. 203.67 What economic criteria must I meet to get royalty relief
on an authorized field or expansion project?
Your field or project must require royalty relief to be economic
and must become economic with this relief. That is, we will not approve
applications if we determine that royalty relief cannot make the field
or project economically viable.
Sec. 203.68 What pre-application costs will MMS consider in
determining economic viability?
(a) We will not consider ineligible costs as set forth in
Sec. 203.89(h) in determining economic viability for purposes of
royalty relief.
(b) We will consider sunk costs (allowable expenditures on and
after the discovery well as specified in Sec. 203.89(a)) in accordance
with the following table.
[[Page 2621]]
------------------------------------------------------------------------
We will-- When--
------------------------------------------------------------------------
Include sunk costs........... The field has not produced, other than
test production, before the application
submission date.
Not include sunk costs....... Determining whether an authorized field
can become economic with any relief (see
Sec. 203.67).
Not include sunk costs....... Determining how much suspension volume is
necessary to make development economic
(see Sec. 203.69(c)).
Not include sunk costs....... Evaluating an expansion project.
------------------------------------------------------------------------
Sec. 203.69 If my application is approved, what royalty relief will I
receive?
This section applies only to leases on which you have applied for
and received a royalty-suspension volume under section 302 of the
DWRRA. We will not collect royalties on a specified suspension volume
for your field. Suspension amounts include volumes allocated to a lease
under an approved unit agreement and exclude any volumes that do not
bear a royalty under the lease or the regulations of this chapter.
(a) For authorized fields, the minimum royalty-suspension volumes
are:
(1) 17.5 million barrels of oil equivalent (MMBOE) for fields in
200 to 400 meters of water;
(2) 52.5 MMBOE for fields in 400 to 800 meters of water; and
(3) 87.5 MMBOE for fields in more than 800 meters of water.
(b) If the application for the field includes leases in different
categories of water depth, we apply the minimum royalty-suspension
volume for the deepest lease then associated with the field. We base
the water depth and makeup of a field on the water-depth delineations
in the ``Royalty Suspension Areas Map'' and the Field Names Master List
and updates in effect at the time your application is approved. These
publications are available from the GOM Regional Office.
(c) You will get a royalty-suspension volume above the minimum if
we determine that you need more to make developing the field economic.
(d) For expansion projects, the minimum suspension volumes do not
apply. If we determine that your expansion project may be economic only
with relief, we will determine and grant you the royalty-suspension
volume necessary to make the project economic.
(e) A royalty-suspension volume will continue through the end of
the month in which cumulative production reaches that volume. The
cumulative production is from all the leases in the authorized field or
expansion project that are entitled to share the royalty suspension
volume.
Sec. 203.70 What information must I provide after MMS approves relief?
You must submit reports to us as indicated in the following table.
Sections 203.81 and 203.90 through 203.91 describe what these reports
must include. MMS's GOM Regional Office will tell you the formats.
------------------------------------------------------------------------
Required report When due to MMS Due date extensions
------------------------------------------------------------------------
Fabricator's confirmation Within 1 year after MMS Director may
report. approval of relief. grant you an
extension under
Sec. 203.79(c) for
up to 1 year.
Post-production report...... Within 60 days after With acceptable
the start of justification from
production that is you, MMS's GOM
subject to the Regional Director
approved royalty- may extend due date
suspension volume. up to 60 days.
------------------------------------------------------------------------
Sec. 203.71 How does MMS allocate a field's suspension volume between
my lease and other leases on my field?
The allocation depends on when production occurs, when the lease is
assigned to the field, and whether we award the volume suspension by an
approved application or establish it in the lease terms.
(a) If your authorized field has an approved royalty-suspension
volume under Secs. 203.67 and 203.69, we will suspend payment of
royalties on production from all applying leases in the field until
their cumulative production equals the approved volume. The following
conditions also apply as appropriate:
------------------------------------------------------------------------
If-- Then-- And--
------------------------------------------------------------------------
We assign an eligible lease We will not change The newly assigned
to your field after we your field's leases may share in
approve or establish relief. royalty-suspension any remaining
volume. royalty relief.
We assign a pre-Act lease to We will not change The newly assigned
your field after you submit your field's leases may share in
a complete application. royalty-suspension any remaining
volume. royalty relief by
filing the short
form application
specified in Sec.
203.83 and
authorized in Sec.
203.82.
We assigned a pre-Act lease We will not change The newly assigned
to your field before you your field's lease will not
submitted the royalty royalty-suspension share in the relief
relief application. volume. if it did not
participate in the
application.
We reassign a well on a pre- The past production The past production
Act lease to another field. from that well from that well will
counts toward the not count toward
royalty suspension any royalty
volume of the field suspension volume
to which the well granted to the
is reassigned. field from which it
was reassigned.
------------------------------------------------------------------------
(b) If your authorized field has an automatic royalty-suspension
volume established under Sec. 260.110 of this chapter, we will suspend
payment of royalties on production from all eligible leases in the
field until their cumulative production equals the automatic volume.
The following conditions also apply as appropriate:
[[Page 2622]]
------------------------------------------------------------------------
If-- Then-- And--
------------------------------------------------------------------------
Another eligible lease is Your field's royalty- The newly assigned
assigned to your field. suspension volume lease may share in
does not change. relief only to the
extent that
cumulative
production from
your field is less
than the automatic
volume.
A pre-Act lease applies Your field's royalty- All leases in the
(along with the other suspension volume field share the
leases in the field) and may increase or one, higher royalty-
qualifies (subject to the stay the same. suspension volume
field's automatic if we approve the
suspension volume) for application;
royalty relief under Secs. or
203.67 and 203.69. The eligible leases
in the field keep
the automatic
volume if we reject
the application.
------------------------------------------------------------------------
(c) If you have an expansion project with more than one lease, the
royalty-suspension volume for each lease equals that 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 approved royalty-
suspension volume.
(d) You may receive a royalty-suspension volume only if your entire
lease is west of 87 degrees, 30 minutes West longitude. If the field
lies on both sides of this meridian, only leases located entirely west
of the meridian will receive a royalty-suspension volume.
Sec. 203.72 Can my lease receive more than one suspension volume?
Yes. You may apply for royalty relief that involves more than one
suspension volume under Sec. 203.62 in two circumstances.
(a) Each field that includes your lease may receive a separate
royalty-suspension volume, if it meets the evaluation criteria of
Sec. 203.67.
(b) An expansion project on your lease may receive a separate
royalty-suspension volume, even if we have already granted a royalty-
suspension volume to the field that encompasses the project. But the
reserves associated with the project must not have been part of our
original determination, and the project must meet the evaluation
criteria of Sec. 203.67.
Sec. 203.73 How do suspension volumes apply to natural gas?
You must measure natural gas production under the royalty-
suspension volume as follows: 5.62 thousand cubic feet of natural gas,
measured in accordance with 30 CFR part 250, subpart L, equals one
barrel of oil equivalent.
Sec. 203.74 When will MMS reconsider its determination?
Under certain conditions, you may request a redetermination if we
deny your application, if you want your approved royalty-suspension
volume to change, after we withdraw approval, or after you renounce
royalty relief. To be eligible for a redetermination, at least one of
the following three conditions must occur.
(a) You have significant new G&G data and you previously have not
either requested a redetermination or reapplied for relief after we
withdrew approval or you relinquished royalty relief. ``Significant''
means that the new G&G data:
(1) Results from drilling new wells or getting new three-
dimensional seismic data and information (but not reinterpreting old
data);
(2) Did not exist at the time of the earlier application; and
(3) Changes your estimates of gross resource size, quality, or
projected flow rates enough to materially affect the results of our
earlier determination.
(b) Your current reference price decreases by more than 25 percent
from your base reference price. For royalty relief on deep water
expansion projects and pre-Act deep water leases:
(1) Your current reference price is a weighted average of daily
closing prices on the NYMEX for light sweet crude oil and natural gas
over the most recent full 12-calendar months;
(2) Your base reference price is a weighted average of daily
closing prices on the NYMEX for oil and gas for the most recent full
12-calendar months preceding the date of your most recently approved
application for this royalty relief; and
(3) The weighting factors are the proportions of the total
production volume (in BOE) for oil and gas associated with the most
likely scenario (identified in Secs. 203.85 and 203.88) from your most
recently approved application for this royalty relief.
(c) Before starting to build your development and production
system, you have revised your estimated development costs, and they are
more than 120 percent of the eligible development costs associated with
the most likely scenario from your most recently approved application
for this royalty relief.
Sec. 203.75 What risk do I run if I request a redetermination?
If you request a redetermination after we have granted you a
suspension volume, you could lose some or all of the previously granted
relief. This can happen because you must file a new complete
application and pay the required fee, as discussed in Sec. 203.62. We
will evaluate your application under Sec. 203.67 using the conditions
prevailing at the time of your redetermination request. In our
evaluation, we may find that you should receive a larger, equivalent,
smaller, or no suspension volume. This means we could find that you do
not qualify for the amount of relief previously granted or for any
relief at all.
Sec. 203.76 When might MMS withdraw or reduce the approved size of my
relief?
We will withdraw approval of relief for any of the following
reasons.
(a) You change the type of development system proposed in your
application (e.g., change from a fixed platform to floating production
system, tension leg platform to a moored catenary system such as a SPAR
platform, an independent development and production system to one with
subsea wells tied back to a host production facility, etc.).
(b) You do not start building the proposed development and
production system within 1 year of the date we approved your
application--unless the MMS Director grants you an extension under
Sec. 203.79(c).
(c) You do not tell us in your post-production development report
(Sec. 203.70), and we find out your actual development costs are less
than 80 percent of the eligible development costs estimated in your
application's most likely scenario. Development costs are those
incurred between the application submission date and start of
production. If you tell us about this result in the post-production
development report, you may retain 50 percent of the original royalty-
suspension volume.
(d) We granted you a royalty-suspension volume after you qualified
[[Page 2623]]
for a redetermination under Sec. 203.74(c), and we find out your actual
development costs are less than 90 percent of the eligible development
costs associated with your application's most likely scenario.
Development costs are those expenditures defined in Sec. 203.89(b)
incurred between your application submission date and start of
production.
(e) You do not send us the fabrication confirmation report or the
post-production development report, or you provide false or
intentionally inaccurate information that was material to our granting
royalty relief under this section. 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.
Sec. 203.77 May I voluntarily give up relief if conditions change?
You may renounce approved royalty-suspension volumes as soon as you
anticipate violating one of the withdrawal conditions, or for any other
reason, before you start production.
Sec. 203.78 Do I keep relief if prices rise significantly?
No, you must pay full royalties if prices rise above the statutory
base price for light sweet crude oil or natural gas.
(a) Suppose the arithmetic average of the daily closing NYMEX light
sweet crude oil prices for the previous calendar year exceeds $28.00
per barrel, as adjusted in paragraph (f) of this section. In this case,
we retract the royalty relief authorized in this section and you must:
(1) Pay royalties on all oil production for the previous year at
the lease stipulated royalty rate plus interest (under 30 U.S.C. 1721
and Sec. 218.54 of this chapter) by April 30 of the current calendar
year, and
(2) Pay royalties on all your oil production in the current year.
(b) Suppose the arithmetic average of the daily closing NYMEX
natural gas prices for the previous calendar year exceeds $3.50 per
million British thermal units (Btu), as adjusted in paragraph (f) of
this section. In this case, we retract the royalty relief authorized in
this section and you must:
(1) Pay royalties on all natural gas production for the previous
year at the lease stipulated royalty rate plus interest (under 30
U.S.C. 1721 and Sec. 218.54 of this chapter) by April 30 of the current
calendar year, and
(2) Pay royalties on all your natural gas production in the current
year.
(c) Production under both paragraphs (a) and (b) of this section
counts as part of the royalty-suspension volume.
(d) You are entitled to a refund or credit, with interest, of
royalties paid on any production (that counts as part of the royalty-
suspension volume):
(1) Of oil if the arithmetic average of the closing oil prices for
the current calendar year is $28.00 per barrel or less, as adjusted in
paragraph (f) of this section, and
(2) Of gas if the arithmetic average of the closing natural gas
prices for the current calendar year is $3.50 per million Btu or less,
as adjusted in paragraph (f) of this section.
(e) You must follow our regulations in part 230 of this chapter for
receiving refunds or credits.
(f) We change the prices referred to in paragraphs (a), (b) and (d)
of this section during each calendar year after 1994. These prices
change by the percentage the implicit price deflator for the gross
domestic product changed during the preceding calendar year.
Sec. 203.79 How do I appeal MMS's decisions related to Deep Water
Royalty Relief?
(a) Once we have designated your lease as part of a field and
notified you and other affected operators of the designation, you can
request reconsideration by sending the MMS Director a letter within 15
days that also states your reasons. The MMS Director's response is the
final agency action.
(b) Our decisions on your application for relief from paying
royalty under Sec. 203.67 and the royalty-suspension volumes under
Sec. 203.69 are final agency actions.
(c) If you cannot start construction by the deadline in
Sec. 203.76(b) for reasons beyond your control (e.g., strike at the
fabrication yard), you may request an extension up to 1 year by writing
the MMS Director and stating your reasons. The MMS Director's response
is the final agency action.
(d) We will notify you of all final agency actions by certified
mail, return receipt requested. Final agency actions are not subject to
appeal to the Interior Board of Land Appeals under 30 CFR part 290 and
43 CFR part 4. They 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 our decision.
Required Reports
Sec. 203.81 What supplemental reports do royalty-relief applications
require?
(a) You must send us the supplemental reports listed below that
apply to your field. Secs. 203.83 through 203.91 describe these reports
in detail.
----------------------------------------------------------------------------------------------------------------
Deep water
Required reports End-of-life expansion Pre-act deep
lease project water lease
----------------------------------------------------------------------------------------------------------------
Administrative information report............................ x x x
Net revenue & relief justification report.................... x ............... ...............
Economic viability & relief justification report (RSVP model
inputs justified by other required reports)................. ............... x x
G&G report................................................... ............... x x
Engineering report........................................... ............... x x
Production report............................................ ............... x x
Deep water cost report....................................... ............... x x
Fabricator's confirmation report............................. ............... x x
Post-production development report........................... ............... x x
----------------------------------------------------------------------------------------------------------------
(b) You must certify that all information in your application,
fabricator's confirmation and post-production development reports is
accurate, complete, and conforms to the most recent content and
presentation guidelines available from the MMS GOM Regional Office.
(c) You must submit with your application and post-production
development report an additional report prepared by a CPA that:
(1) Assesses the accuracy of the historical financial information
in your report; and
(2) Certifies that the content and presentation of the financial
data and
[[Page 2624]]
information conforms to our most recent guidelines on royalty relief.
(d) You must identify the people in the CPA firm who prepared the
reports referred to in paragraph (c) of this section and make them
available to us to respond to questions about the historical financial
information. We may also further review your records to support this
information.
Sec. 203.82 What is MMS's authority to collect this information?
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.
(a) We use the information to determine whether royalty relief will
result in production that wouldn't otherwise occur. We rely largely on
your information to make these determinations.
(1) Your application for royalty relief must contain enough
information on finances, economics, reservoirs, G&G characteristics,
production, and engineering estimates for us to determine whether:
(i) We should grant relief under the law, and
(ii) The requested relief will ultimately recover more resources
and return a reasonable profit on project investments.
(2) Your fabricator confirmation and post-production development
reports must contain enough information for us to verify that your
application reasonably represented your plans.
(b) Applicants (respondents) are Federal OCS oil and gas lessees.
Applications are required to obtain or retain a benefit. Therefore, if
you apply for royalty relief, you must provide this information. We
will protect information considered proprietary under applicable law
and under regulations at Sec. 203.63(b) and part 250 of this chapter.
(c) The Paperwork Reduction Act of 1995 requires us to inform you
that we may not conduct or sponsor, and you are not required to respond
to, a collection of information unless it displays a currently valid
OMB control number.
(d) You may send comments regarding any aspect of the collection of
information under this part, including suggestions for reducing the
burden, to the Information Collection Clearance Officer, Minerals
Management Service, Mail Stop 4230, 1849 C Street, N.W., Washington, DC
20240; and to the Office of Information and Regulatory Affairs, Office
of Management and Budget, Attention: Desk Officer for the Department of
the Interior (1010-0071), Washington, DC 20503.
Sec. 203.83 What is in an administrative information report?
This report identifies the field or lease for which royalty relief
is requested and must contain the following items:
(a) The field or lease name;
(b) The serial number of leases we have assigned to the field,
names of the lease title holders of record, the lease operators, and
whether any lease is part of a unit;
(c) Lessee's designation, the API number and location of each well
that has been drilled on the field or lease or project (not required
for non-oil and gas leases);
(d) The location of any new wells proposed under the terms of the
application (not required for non-oil and gas leases);
(e) A description of field or lease history;
(f) Full information as to whether you will pay royalties or a
share of production to anyone other than the United States, the amount
you will pay, and how much you will reduce this payment if we grant
relief;
(g) The type of royalty relief you are requesting;
(h) Confirmation that we approved a DOCD or supplemental DOCD (Deep
Water expansion project applications only); and
(i) 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 (Deep
Water applications only).
Sec. 203.84 What is in a net revenue and relief justification report?
This report presents cash flow data for 12 qualifying months, using
the format specified in the ``Guidelines for the Application, Review,
Approval, and Administration of Royalty Relief for End-of-Life
Leases'', U.S. Department of the Interior, MMS. Qualifying months for
an oil and gas lease are the most recent 12 months out of the last 15
months that you produced at least 100 BOE per day on average.
Qualifying months for other than oil and gas leases are the most recent
12 of the last 15 months having some production.
(a) The cash flow table you submit must include historical data
for:
(1) Lease production subject to royalty;
(2) Total revenues;
(3) Royalty payments out of production;
(4) Total allowable costs; and
(5) Transportation and processing costs.
(b) Do not include in your cash flow table the non-allowable costs
listed at 30 CFR 220.013 (a), (b), and (d) through (k) or:
(1) OCS rental payments on the lease(s) in the application;
(2) Damages and losses;
(3) Taxes;
(4) Any costs associated with exploratory activities;
(5) Civil or criminal fines or penalties;
(6) Fees for your royalty relief application; and
(7) Costs associated with existing obligations (e.g., royalty
overrides or other forms of payment for acquiring the lease).
(c) We may, in reviewing and evaluating your application, disallow
costs when you have not shown they are necessary to operate the lease,
or if it appears you spent the money only to qualify for royalty
relief.
Sec. 203.85 What is in an economic viability and relief justification
report?
This report should show that your project appears economic without
royalties and sunk costs using the RSVP model we provide. The format of
the report and the assumptions and parameters we specify are found in
the ``Guidelines for the Application, Review, Approval and
Administration of the Deep Water Royalty Relief Program,'' U.S.
Department of the Interior, MMS. Clearly justify each parameter you set
in every scenario you specify in the RSVP. You may provide supplemental
information, including your own model and results. The economic
viability and relief justification report must contain the following
items for an oil and gas lease.
(a) Economic assumptions we provide which include:
(1) Starting oil and gas prices;
(2) Real price growth;
(3) Real cost growth or decline rate, if any;
(4) Base year;
(5) Range of discount rates; and
(6) Tax rate (for use in determining after-tax sunk costs).
(b) Analysis of projected cash flow (from the date of the
application using annual totals and constant dollar values) which
shows:
(1) Oil and gas production;
(2) Total revenues;
(3) Capital expenditures;
(4) Operating costs;
(5) Transportation costs; and
(6) Before-tax net cash flow without royalties, overrides, sunk
costs, and ineligible costs.
(c) Discounted values which include:
[[Page 2625]]
(1) Discount rate used (selected from within the range we specify).
(2) Before-tax net present value without royalties, overrides, sunk
costs, and ineligible costs.
(d) Demonstrations that:
(1) All costs, gross production, and scheduling are consistent with
the data in the G&G, engineering, production, and cost reports
(Secs. 203.86 through 203.89) and
(2) The development and production scenarios provided in the
various reports are consistent with each other and with the proposed
development system. You can use up to three scenarios (conservative,
most likely, and optimistic), but you must link each to a specific
range on the distribution of resources from the RSVP Resource Module.
Sec. 203.86 What is in a G&G report?
This report supports the reserve and resource estimates used in the
economic evaluation and must contain each of the following elements.
(a) Seismic data which includes:
(1) Non-interpreted 2D/3D survey lines reflecting any available
state-of-the-art processing technique in a format readable by MMS and
specified by the deep water royalty relief guidelines;
(2) Interpreted 2D/3D seismic survey lines reflecting any available
state-of-the-art processing technique identifying all known and
prospective pay horizons, wells, and fault cuts;
(3) Digital velocity surveys in the format of the GOM region's
letter to lessees of 10/1/90;
(4) Plat map of ``shot points;'' and
(5) ``Time slices'' of potential horizons.
(b) Well data which includes:
(1) Hard copies of all well logs in which--
(i) The 1-inch electric log shows pay zones and pay counts and
lithologic and paleo correlation markers at least every 500-feet,
(ii) The 1-inch type log shows missing sections from other logs
where faulting occurs,
(iii) The 5-inch electric log shows pay zones and pay counts and
labeled points used in establishing resistivity of the formation, 100
percent water saturated (Ro) and the resistivity of the
undisturbed formation (Rt), and
(iv) The 5-inch porosity logs show pay zones and pay counts and
labeled points used in establishing reservoir porosity or labeled
points showing values used in calculating reservoir porosity such as
bulk density or transit time;
(2) Digital copies of all well logs spudded before December 1,
1995;
(3) Core data, if available;
(4) Well correlation sections;
(5) Pressure data;
(6) Production test results; and
(7) Pressure-volume-temperature analysis, if available.
(c) Map interpretations which includes for each reservoir in the
field:
(1) Structure maps consisting of top and base of sand maps showing
well and seismic shot point locations;
(2) Isopach maps for net sand, net oil, net gas, all with well
locations;
(3) Maps indicating well surface and bottom hole locations,
location of development facilities, and shot points; and
(4) Identification of reservoirs not contemplated for development.
(d) Reservoir-specific data which includes:
(1) Probability of reservoir occurrence with hydrocarbons;
(2) Probability the hydrocarbon in the reservoir is all oil and the
probability it is all gas;
(3) Distributions or point estimates (accompanied by explanations
of why distributions less appropriately reflect the uncertainty) for
the parameters used to estimate reservoir size, i.e., acres and net
thickness;
(4) Most likely values for porosity, salt water saturation, volume
factor for oil formation, and volume factor for gas formation;
(5) Distributions or point estimates (accompanied by explanations
of why distributions less appropriately reflect the uncertainty) for
recovery efficiency (in percent) and oil or gas recovery (in stock-
tank-barrels per acre-foot or in thousands of cubic feet per acre
foot);
(6) A gas/oil ratio distribution or point estimate (accompanied by
explanations of why distributions less appropriately reflect the
uncertainty) for each reservoir; and
(7) A yield distribution or point estimate (accompanied by
explanations of why distributions less appropriately reflect the
uncertainty) for each gas reservoir.
(e) Aggregated reserve and resource data which includes:
(1) The aggregated distributions for reserves and resources (in
BOE) and oil fraction for your field computed by the resource module of
our RSVP model;
(2) A description of anticipated hydrocarbon quality (i.e.,
specific gravity); and
(3) The ranges within the aggregated distribution for reserves and
resources that define the development and production scenarios
presented in the engineering and production reports. Typically there
will be three ranges specified by two positive reserve and resource
points on the aggregated distribution. The range at the low end of the
distribution will be associated with the conservative development and
production scenario; the middle range will be related to the most
likely development and production scenario; and, the high end range
will be consistent with the optimistic development and production
scenario.
Sec. 203.87 What is in an engineering report?
This report defines the development plan and capital requirements
for the economic evaluation and must contain the following elements.
(a) A description of the development concept (e.g., tension leg
platform, fixed platform, floater type, subsea tieback, etc.) which
includes:
(1) Its size and
(2) The construction schedule.
(b) An identification of planned wells which includes:
(1) The number;
(2) The type (platform, subsea, vertical, deviated, horizontal);
(3) The well depth;
(4) The drilling schedule;
(5) The kind of completion (single, dual, horizontal, etc.); and
(6) The completion schedule.
(c) A description of the production system equipment which
includes:
(1) The production capacity for oil and gas and a description of
limiting component(s);
(2) Any unusual problems (low gravity, paraffin, etc.);
(3) All subsea structures;
(4) All flowlines; and
(5) Schedule for installing the production system.
(d) A discussion of any plans for multi-phase development which
includes:
(1) The conceptual basis for developing in phases and goals or
milestones required for starting later phases; and
(2) An explanation for excluding the reservoirs you are not
planning to develop.
(e) A set of development scenarios consisting of activity timing
and scale associated with each of up to three production profiles
(conservative, most likely, optimistic) provided in the production
report for your field (Sec. 203.88). Each development scenario and
production profile must denote the likely events should the field size
turn out to be within a range represented by one of the three segments
of the field size distribution. If you send in fewer than three
scenarios, you must explain why fewer scenarios are more efficient
across the whole field size distribution.
[[Page 2626]]
Sec. 203.88 What is in a production report?
This report supports your development and production timing and
product quality expectations and must contain the following elements.
(a) Production profiles by well completion and field that specify
the actual and projected production by year for each of the following
products: oil, condensate, gas, and associated gas. The production from
each profile must be consistent with a specific level of reserves and
resources on the aggregated distribution of field size.
(b) Production drive mechanisms for each reservoir.
Sec. 203.89 What is in a deep water cost report?
This report lists all actual and projected costs for your field,
must explain and document the source of each cost estimate, and must
identify the following elements.
(a) Sunk cost, which are all your eligible post-discovery
exploration, development, and production expenses (no third party
costs), and also include the eligible costs of the discovery well on
the field. Report them in nominal dollars and only if you have
documentation. We count sunk costs in an evaluation (specified in
Sec. 203.68) as after-tax expenses, using nominal dollar amounts.
(b) Appraisal, delineation and development costs. Base them on
actual spending, current authorization for expenditure, engineering
estimates, or analogous projects. These costs cover:
(1) Platform well drilling and average depth;
(2) Platform well completion;
(3) Subsea well drilling and average depth;
(4) Subsea well completion;
(5) Production system (platform); and
(6) Flowline fabrication and installation.
(c) Production costs based on historical costs, engineering
estimates, or analogous projects. These costs cover:
(1) Operation;
(2) Equipment; and
(3) Existing royalty overrides (we will not use the royalty
overrides in evaluations).
(d) Transportation costs, based on historical costs, engineering
estimates, or analogous projects. These costs cover:
(1) Oil or gas tariffs from pipeline or tankerage;
(2) Trunkline and tieback lines; and
(3) Gas plant processing for natural gas liquids.
(e) Abandonment costs, based on historical costs, engineering
estimates, or analogous projects. You should provide the costs to plug
and abandon only wells and to remove only production systems for which
you have not incurred costs as of the time of application submission.
You should also include a point estimate or distribution of prospective
salvage value for all potentially reusable facilities and materials,
along with the source and an explanation of the figures provided.
(f) A set of cost estimates consistent with each one of up to three
field-development scenarios and production profiles (conservative, most
likely, optimistic). You should express costs in constant real dollar
terms for the base year. You may also express the uncertainty of each
cost estimate with a minimum and maximum percentage of the base value.
(g) A spending schedule. You should provide costs for each year (in
real dollars) for each category in paragraphs (a) through (f) of this
section.
(h) A summary of other costs which are ineligible for evaluating
your need for relief. These costs cover:
(1) Expenses before first discovery on the field;
(2) Cash bonuses;
(3) Fees for royalty relief applications;
(4) Lease rentals, royalties, and payments of net profit share and
net revenue share;
(5) Legal expenses;
(6) Damages and losses;
(7) Taxes;
(8) Interest or finance charges, including those embedded in
equipment leases;
(9) Fines or penalties; and
(10) Money spent on previously existing obligations (e.g., royalty
overrides or other forms of payment for acquiring a financial position
in a lease, expenditures for plugging wells and removing and abandoning
facilities that existed on the application submission date).
Sec. 203.90 What is in a fabricator's confirmation report?
This report shows you have committed in a timely way to the
approved system for production. This report must include the following
(or its equivalent for unconventionally acquired systems):
(a) A copy of the contract(s) under which the fabrication yard is
building the approved system for you;
(b) A letter from the contractor building the system to the MMS's
GOM Regional Supervisor--Production and Development, certifying when
construction started on your system; and
(c) Evidence of an appropriate down payment or equal action that
you've started acquiring the approved system.
Sec. 203.91 What is in a post-production development report?
For each cost category in the deep water cost report, you must
compare actual costs up to the date when production starts to your
planned pre-production costs. If your application included more than
one development scenario, you need to compare actual costs with those
in your scenario of most likely development. Keep supporting records
for these costs and make them available to us on request.
[FR Doc. 98-842 Filed 1-15-98; 8:45 am]
BILLING CODE 4310-MR-P
