[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.

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

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                                         
----------------------------------------------------------------------------------------------------------------
            Requirement/Subject                          Comment                          MMS Response          
----------------------------------------------------------------------------------------------------------------
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.                           
----------------------------------------------------------------------------------------------------------------


                               Comments on Net Revenue Share (NRS) Royalty Relief                               
----------------------------------------------------------------------------------------------------------------
            Requirement/Subject                          Comment                          MMS Response          
----------------------------------------------------------------------------------------------------------------
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)                                  
----------------------------------------------------------------------------------------------------------------
        Requirement/Subject                                 Comment                             MMS Response    
----------------------------------------------------------------------------------------------------------------
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