Royalty management: 2000 OCS oil and gas leases,
[Federal Register: January 15, 2002 (Volume 67, Number 10)]
[Rules and Regulations]
[Page 1862-1880]
From the Federal Register Online via GPO Access [wais.access.gpo.gov]
[DOCID:fr15ja02-3]
DEPARTMENT OF THE INTERIOR
Minerals Management Service
RIN 1010-AC71
Relief or Reduction in Royalty Rates--Deep Water Royalty Relief for OCS Oil and Gas Leases Issued After 2000
AGENCY: Minerals Management Service (MMS), Interior.
ACTION: Final rule.
SUMMARY: This rule revises regulations on royalty relief for oil and gas producers on the Outer Continental Shelf (OCS). It provides for suspension or reduction of royalty on a case-by-case basis for certain additional categories of OCS leases under part 203 of this title. Also, it identifies circumstances when we may consider royalty relief apart from our end-of-life and deepwater royalty relief (DWRR) programs.
DATES: This final rule is effective February 14, 2002.
FOR FURTHER INFORMATION CONTACT: Marshall Rose, Economics Division, at (703) 787-1536.
SUPPLEMENTARY INFORMATION: On November 16, 2000, we published a proposed rule in the Federal Register (65 FR 69259). For leases that lie in water 200 meters or deeper in the Gulf of Mexico (GOM) wholly west of 87 degrees, 30 minutes West longitude and issued after November 2000, it provided a process to apply for supplemental royalty relief. Also, it proposed to modify the relief qualification process. Some proposed modifications apply only to leases issued after November 2000 (newly issued leases) while others apply both to leases issued before the DWRR Act (pre-Act leases) and to newly issued leases. These proposed modifications sought to combine more opportunity, certainty, and flexibility for applicants with a royalty relief determination process more focused on future costs and benefits. We requested comments on these proposed changes.
We also finalized in the Federal Register on February 23, 2001 (66 FR 11512) regulations on the way we implement OCS leasing incentives on newly issued leases. The opportunity for newly issued leases to qualify for royalty relief that supplements lease-term incentives when we issued them is an important part of the change in these incentives.
Several comments on the proposed rulemaking addressed the changed leasing incentives and the modifications to the royalty relief qualification process. This final rule makes changes from the proposed rule in response to
[[Page 1863]]
comments we received. The most significant changes relate to sunk costs and the timing of our evaluations.
As sunk costs, which we use to determine only qualification, not the volume suspension amount, we proposed to count only the cost of the project's first discovery well. Comments convinced us that a more expansive definition was appropriate. This final rule allows the costs of the first project discovery well on each lease. We believe this provides the proper balance between the need to encourage exploration of marginal future prospects and the lack of any role sunk costs have in determining economic viability after a discovery.
With respect to timing, we proposed to retain the 180-day period for our review of royalty relief requests for projects. Comments indicated a strong desire for a shorter period. Efficiencies from evaluating expansion or development projects, instead of fields (as required for applications involving pre-Act leases), can reduce our average evaluation time by 1 month. Hence, this final rule lowers our timeframe for evaluating development or expansion projects, but not for fields, from 180 to 150 days.
Response to Comments
We received a joint comment from six oil and gas industry associations, and separate comments from one of those associations and from five oil and gas companies in response to our request for written comments on our proposed rulemaking. Also, two public workshops raised questions on the proposed rule. Copies of all the written comments we received are available on our Web site at http://www.mms.gov/ federalregister/PublicComments/rulecomm.htm.
We analyzed all comments and workshop questions and revised the final language based on many of them. The main changes from the proposed rule involve a more expansive definition of allowable sunk cost, a shorter evaluation period, and more specificity on several subjective terms (significant expansion, most likely resource size, most efficient development system).
Two changes from the proposed version of this rule make the final version consistent with changes made in the companion rule on OCS leasing incentives. Finally, we note provisions where we adjusted the language to clarify but not change the meaning from the proposed rule.
Supplementary Relief
One general comment objected to reliance on discretionary royalty relief because of administrative burdens and increased costs to industry.
Response: We agree that the discretionary royalty relief program will become more important when leases issued after 2000 represent significant amounts of acreage and discoveries in the deep water GOM. But it will be many years before post-2000 leases play a significant role in deepwater development. As we explained in earlier Federal Register notices on continuing royalty relief in deep water, most of the prospective deepwater tracts now have access to the royalty suspension volumes prescribed by the DWRR Act. Some 3,400 eligible leases already have the potential to receive royalty suspension automatically. Another nearly 1,700 pre-Act leases may qualify for royalty relief under discretionary relief regulations that have been in place for several years. The currently leased acreage--eligible and pre-Act leases--represents almost half of the deep water GOM acreage. These handpicked opportunities, which industry believes have the best hydrocarbon prospects, will occupy the available exploration and delineation capability in the GOM for many years. Much of the new production in deep water over the next decade or so may be royalty- free. Hence, we anticipate that the overall royalty expenses for deepwater oil and gas production will decrease for some time completely independent of future terms and conditions on newly offered tracts.
We expect to process applications more quickly and efficiently as we become more experienced in handling them. These final discretionary relief regulations follow the directive in the DWRR Act to consider granting royalty suspension only in those circumstances when otherwise developable production would be uneconomic because of normal royalty obligations. Thus only some, not all, leases should be concerned with or have a need for the discretionary royalty relief program. Further, to encourage development, we make the uneconomic determination not after production occurs, but before, using forecasts of many variables. The determination unavoidably involves the collection, analysis, and evaluation of detailed information. Questions about possible inconsistencies or options in a specific development proposal often only become apparent during the review process. Evaluation then sometimes requires additional information. Computing and documenting forecasts tied to the circumstances of a specific project proposal may appear cumbersome at times, but a sound determination requires that we understand the key assumptions and risks in the applicant's proposed project.
The comment most relevant to our request for paperwork reduction suggestions was the acknowledgment that ``the majority of the information requested by MMS is necessary * * * for a comprehensive review of a proposed project.'' We have added language to encourage potential applicants to meet with MMS prior to filing an application to identify unusual elements in the project and for guidance on application format, content, and our evaluation perspective. See Sec. 203.62(c).
Several proposed changes we finalized expedite the evaluation process by making it less burdensome. We designate the applicant's project and the reservoirs targeted by the proposed project as the application unit rather than the entire field, as in the current DWRR program. Thus the applicant no longer must involve adjacent lessees in the application, and we no longer need to speculate about additional resources that may affect field economics. Also, this change reduces the need for us to evaluate alternative field development scenarios. Other changes should reduce the burden on both pre-Act lease applicants and new lease applicants by giving them more flexibility to adjust to changing conditions. We extend the time period for successful applicants to commit to development and allow reapplication in a wider range of circumstances. Potential applicants will become more comfortable with our application and evaluation process by the time the burden for DWRR shifts more to the discretionary royalty relief program.
Sunk Costs
A number of comments expressed concerns about the limited allowance of sunk costs to evaluate the economics of a proposed project.
Response: Our proposed change in allowable sunk costs--from all costs of and after discovery to only those of the discovery well-- received the most comments from industry. That reaction may indicate that limiting allowable sunk costs is perceived as the most important proposed change to the discretionary royalty relief rules. The size of sunk costs has been the main reason for royalty relief qualification in our determinations to date. We proposed no change to the treatment of sunk costs in applications from non-producing pre-Act leases to keep within the DWRR Act. Also, we proposed to add for the first time some sunk costs to our evaluation of expansion projects. Nonetheless, in light of its perceived and past importance, we expand our
[[Page 1864]]
definition of allowable sunk costs for applications from leases issued after 2000 and for expansion projects on pre-Act leases.
One workshop comment suggested that the definition of allowable sunk costs include the cost of the first well on each lease that discovers hydrocarbons in the reservoirs included in the application. We adopt this new definition because it includes the most important and readily identifiable delineation costs on a project.
This more expansive definition of sunk costs may encourage more development and more exploration than otherwise. Historic costs theoretically do not affect the expected profitability of a particular project, as measured from the perspective of its application date. But, their treatment can influence decisions on the timing and magnitude of pre-application exploration, drilling, and appraisal. Using sunk costs in an evaluation makes qualification for discretionary royalty relief more likely. The more likely that a prospect of a given size will qualify for relief, the larger the expected value of that prospect. And, the higher the expected payoff from drilling, the more and sooner drilling will take place.
We choose to rely on supplemental discretionary royalty relief to concentrate royalty savings on prospects that show a need for it. General lease sale incentives disperse royalty relief over all lease prospects regardless of whether they need development assistance. In a system where supplemental royalty relief plays a large role in the incentive program, it may not be appropriate to narrowly define qualification for the supplemental relief based on theoretical rather than practical considerations.
While an expansive consideration of sunk costs is in order, we believe the broad definition applicable to pre-Act leases is not appropriate for newer leases. The object of the new supplemental royalty relief program is a specific and fully identified project, rather than a whole, often incompletely identified, field. A royalty relief determination on a field with pre-Act leases requires evaluation of all resources that may ultimately be assigned to that field and of associated development options. The broad field determination provides a basis for considering all possible resources and thus the sunk costs for a wide range of appraisal activities. Project royalty relief determination, on the other hand, is confined to the reservoirs identified in the application. Relief qualification need not consider alternative development options or potential production from other reservoirs. So, fewer post-discovery expenditures are relevant to a project application. Therefore, we will count the costs of only the discovery well for the project on each lease participating in an application for other than an authorized field. To clarify the revision as well as the distinction, we separate the definition of sunk costs for authorized fields from the definition of sunk costs for development and expansion projects and move identification of the critical elements to the definitions from the cost report description in Sec. 203.89 (a). See changes in Secs. 203.0 and 203.68.
We continue to count allowable sunk costs on an after-tax, nominal basis. A company recoups part of exploratory drilling costs through a deduction from taxable income. Crediting all the pre-tax costs to royalty relief qualification would substantially raise the benefit accorded sunk costs. Adjusting sunk costs for inflation could reward applicants that delay applying for royalty relief.
Other Comments
The written comments and workshop questions raised a number of specific or technical issues. The following table summarizes and responds to each of those issues. We arranged the table according to the section in the rule to which the comment relates. The last part of the table addresses comments on information collection under the Paperwork Reduction Act.
Industry comments CFR section
and questions
MMS response
203.0, 203.2, and 203.4..... Delete the word Accommodating ``significant'' change. The DWRR from the
Act used the word definitions of an ``significant'' to expansion project direct relief to and of new
projects that add production because new resources, not it is too
those that simply subjective when extend recovery of left to the
reservoirs already discretion of the in production. We application process. delete ``significant'' from the definition of ``new production'' and clarify in the definition of ``expansion project,'' that it refers to one or more new wells drilled into a reservoir that has not previously produced. Also, we modify the definition of ``new production'' accordingly. 203.0 and 203.60............ Don't limit
No change. The DWRR development
Act gives authority projects that can to grant royalty apply for deepwater relief to existing royalty suspension non-producing to those on leases leases, but only west of 87 degrees those in this part 30 minutes West of the GOM. We may longitude in the issue new leases GOM.
with a variety of terms, including royalty suspension, in other parts of the OCS. 203.0, 203.4, 203.70, and Eliminate from the No change. The 203.81.
definition of
legitimacy of the fabrication a
royalty relief requirement for a qualification requirement for a determination letter from the depends on prompt fabricator
development. We see certifying start of value in having a continuous
third party witness construction
an event that has because it is an such important to unnecessary and an applicant. The redundant burden. down payment and contract alone may not ensue that the operator has actually committed to construction that will not be interrupted after it has started. The notice could be just a copy of whatever normal notification the applicant gets from the fabricator that construction has started on its system, with the intent to continued without interruption.
[[Page 1865]]
203.0, 203.68, and 203.89... Redefine sunk costs Accommodating as all of the
change. We have inflation adjusted enlarged the scope before-tax costs of sun costs from of, and after,
the proposed rule. discovery up until But historic costs the application. have questionable relevance to proceeding with development of the project in the application. Also, many such costs have already been recovered through tax deductions and subsequent savings. The expansion in the definition is limited to discovery well costs for one eligible well per lease. 203.0, 203.68, and 203.89... Does MMS want to We want a reliable receive
application. The applications before applicant is the delineation wells only one in a are drilled which position to balance help in the
the costs and decision on the benefits of development
incremental approach.
delineation. Performance conditions help encourage a proper balance--enough data in hand for the applicant to commit to a few key decisions but not to detailed development plans. 203.2 and 203.80............ Delete the word Accommodating ``significantly'' change. We delete word from the
the word from the characterization of end-of-life relief how much production cell in the table must increase as a in Sec. 203.2, but result of royalty as with deepwater relief because it expansion projects, is too subjective. we look for a minimum production increase for consideration of royalty relief apart from our formal programs. Relief generally must make production for an extra year profitable. 203.4, 203.69 and 203.76.... Clarify the resource Change. By ``most number used as a likely resource basis for
size'' we mean the determining the median value of the minimum royalty estimated suspension volume. distribution of known recoverable resources from reservoirs included in the application for the project. The final rule adopts this more precise terminology. 203.4....................... Indicate that price Change. We make thresholds will be clear in specified in the subsections (e) and Notice of Sale as (f) that price well as in the
thresholds and lease document. minimum suspension volumes may be set in the Notice of Sale or the regulations or in the lease. 203.62...................... Encourage pre-
Change. Such a application
meeting can save meetings between time both in the MMS regional preparing an office and a
application and in prospective
avoiding omissions applicant.
that delay the evaluation process. 203.63...................... Clarify that neither Change. We also make a development nor the same expansion project clarification that must include all ``project'' means leases in its field. development either expansion project or development project in Secs. 203.64, 203.65, 203.67, 203.68, and 203.69. 203.65...................... Change the
Accommodating evaluation deadline change. We reduce from 180 to 120 the evaluation days for a first period for application and development from 120 to 90 for projects and a redetermination. expansion projects to no more than 150 days after certifying an application and application complete. For field evaluations involving pre-Act leases, the 180-day deadline continues because we must consider potential development of all resources on the field, whether or not they are identified in the application. 203.69...................... If a participating A lessee can join lease doesn't have the application or propose, a well with evidence that into the reservoirs the reservoir(s) included in the targeted by the application, does project occur on MMS include in the its lease. However, minimum suspension a lease without volume calculation enough of the the royalty
project's resources suspension volume to justify a well with which the
cannot include its lease was
automatic royalty originally issued? suspension volume in the minimum set for the project. Nevertheless, we will count its estimated resources in the project evaluation and in the increment to the minimum royalty suspension volume based on the median of the distribution of resources. 203.69 and 203.76........... Does a lease retain Since the the royalty
application suspension volume qualification with which it was included originally issued consideration of if it applies and the pre-existing qualifies for
royalty suspension project relief but on the lease, it then violates a retains that relief performance
if we withdraw condition.
approval of its application. We don't want to discourage early- stage applications when some development decisions have not yet been made. 203.71...................... If a lease is added If the reservoir(s) to a project after targeted by the approval of an
development project application, does extend to a post- the added lease 2000 lease, that have to give up its lessee has an automatic relief to option. The lessee be part of the
may file a short project.
form to share the project's remaining royalty suspension volume or simply retain its automatic royalty suspension volume for use with this or other reservoirs on its lease. If it files the short form to share in the project relief, it gives up its automatic relief volume. 203.74...................... A phrase is missing Accommodating in the description change. We rewrote of the new event to clarify that the that enables a
new technology must redetermination. improve the profitability, under equivalent market conditions, of the field or specified set of reservoirs relative to the development system proposed in the prior application.
[[Page 1866]]
203.76...................... Allow retention of No change. We made half of the royalty the modification in suspension volume, the proposed rule not the smaller of because otherwise that or the most small fields face likely resource no disadvantage for size, when costs overestimating are overestimated their costs in a in the application. royalty relief application. 203.78...................... If the price
We provide a threshold suspends reasonable relief when prices inducement to make rise too much above a project economic expected levels, under expected why not augment market conditions. initial royalty This is the focus suspension volume of our program. if prices fall too Subsequent much below expected deviations in these levels.
conditions during periods of production and potential relief from royalties may change profitability, but are not likely to affect project viability. Should prices decline once production begins, the lessee can pursue our other royalty relief programs. These programs serve as a proxy for predetermined increases in royalty suspension volume for a price decline. 203.80...................... Allow the costs of Change. Off-lease pre-existing
facilities tied facilities that back to the lease help justify a
may help justify a royalty relief
relief application application to be to the extent that off lease.
preservation of these pre-existing facilities depends on continued application to be production from the lease applying for royalty relief. We will include only a logically allocable share of costs from the off-lease facilities. Information Collection
(
-
Under the
(a)We have not Questions.
current evaluation identified an process,
alternative acknowledgement evaluation process that the majority suitable for use of the information with an irrevocable requested in an determination such application is
as royalty relief. necessary.
Past applicants and industry committees have not yet identified any unnecessary information elements. (b) Contact past (b) We welcomed applicants to very comments from past estimates of the applicants to help time it takes to develop our current fill out an
estimates of the application.
burden. (c) Standardize the (c) We have various application standardized reports that must reports as much as be submitted or we can, and we do generate a set of invite pre- generic example application reports as guides consultation on for future
format and content. applicants.
We do not share past applications even in generalized form so as to avoid possibly exposing proprietary information. We already offer an example with the model that combines the information in these reports. That should clarify many questions about technical details such as units of measure. (d) MMS mail server (d) We are limits make it
implementing the impractical to
Government submit the original Paperwork application
Elimination Act electronically, but (GPEA). The Act subsequent
calls for providing information could an electronic usually be
processing option submitted by e-mail. when practical for information we collect. Royalty relief applications are under review in our GPEA implementation information program. We do currently accept extra copies and additional information by electronic or fax means.
Changes for Consistency and Clarity
We make two changes in this rule on discretionary royalty relief to make it consistent with our rule on OCS leasing incentives published on February 23, 2001 (66 FR 11512). Also, we use definitions for ``eligible,'' ``pre-Act,'' and ``royalty suspension'' leases in this rule that are identical to those in the leasing incentive rule.
The leasing incentive rule includes the option to offer royalty incentives for a value of production or for a time period as well as for a volume of production. The definition of Royalty Suspension (RS) leases in Sec. 203.0 now indicates that the royalty suspension for an RS lease need not be in the form of a volume. So, one or more leases on a project applying for additional royalty relief may have automatic suspensions in a form other than volume. Section 203.69(b) now indicates that should this situation arise, we will use the data in your application, after any adjustments we make during our evaluation, to convert royalty relief already available to a common basis expressed in volume, and carry out the evaluation accordingly. Any approval would be expressed solely in terms of volume.
The leasing incentive rule also includes a provision in Sec. 260.122(b)(2) for paying royalties, due as a result of the price threshold being exceeded, no later than 90 days after the end of the period for which royalty is owed. That deadline is shorter than the 120-day interval to April 30 now specified in Sec. 203.78(a)(1) and (b)(1). To avoid confusion, we changed Sec. 203.78 to be consistent with Sec. 260.122. The 90-day time lag is longer than the 30-day time lag for payment of normal royalty under Sec. 218.50 because we must calculate inflation adjustments in the case of price thresholds. The actual NYMEX price can be calculated immediately after the end of the period specified, but the final value for the implicit price deflator for the gross domestic product is not generally available for several months after the end of the period.
In several places, we modified the language in the proposed rule to make its meaning clearer to the reader.
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CFR section
Clarification
203.0............................. We enhance definitions to: (1) State that development or expansion projects must be in water at least 200 meters deep, (2) Declare that redetermination is a procedure we conduct under certain conditions at your request, and (3) Illustrate some elements of eligible sunk costs incurred before a discovery. 203.2............................. We replace ``when'' with ``how'' in the title question. Unlike ``expansion project'' ``authorized field'' and ``development project,'' ``end-of- life lease'' is a term defined here but not in Sec. 203.0. We drop reference to significant capital investment by an expansion project because that is not a separate requirement for an expansion project on a lease issued after 2000. The flexibility of royalty relief apart from our formal programs may involve changes in the form of the royalty as well as in its size or duration. 203.4............................. We more carefully explain how to interpret the tables summarizing our royalty relief programs. End-of-Life relief is now withdrawn only when the effective royalty rate has prevailed for 12 consecutive months. We drop reference to charging more than the original lease royalty rate after the suspension volume has been produced. 203.4 and 203.69.................. The various forms of royalty relief we grant are subject to certain conditions set out in regulations or approval letters. We rephrase the way one determines cumulative production. 203.60............................ We reversed the phrases in the lead sentence. We stipulate that pre-Act leases, but not leases issued after 2000, must have been assigned to a field as well as have a discovery prior to applying for royalty suspension. 203.63............................ You must, rather than may, submit data you have on leases that you believe may become part of your authorized field in the future. 203.64............................ Only one application may be filedon a development project designed to produce a specific set of reservoirs. 203.66............................ We make explicit that prescribed evaluation deadlines may be extended and rephrase the table lead-in sentence. We clarify that a penalty suspension for our late determination applies to the first production from a development project. 203.68............................ We do not consider sunk costs when we determine whether a project is economic should it never have to pay royalties. 203.69............................ We substitute the new name for the publication that gives the water depth of each lease. 203.71............................ Eligible leases as well as RS leases retain the royalty suspension volumes with which they start an application process, even if we reject an application that requests more relief on a field or development project. Applying leases are ones that participate in the application for royalty relief. Leases issued without a royalty suspension volume do not share the relief for a field with an automatic royalty suspension volume. We drop reference to the impossible situation of adding a lease before you submit an application from the paragraph (a) that describes the effect of adding a lease to an authorized field after we have approved royalty relief. 203.74............................ The discussion in the sub-elements of (c) explains a procedure for calculating prices, not determining eligibility for a reconsideration of a royalty relief determination. 203.78............................ Different price thresholds may apply to different leases on the same field, development project, or expansion project. Different price thresholds could occur if the leases were issued at different times. And, only the base oil and gas price thresholds for pre-Act leases are adjusted from 1994 forward. Post-2000 lease price thresholds are adjusted forward from other periods as specified in their Notice of Sale or lease documents. 203.80............................ We no longer formally refer to royalty relief apart from our end- of-life or deepwater programs as ``special''. 203.83............................ We require a well number and status as part of the Administrative Information Report. 203.89............................ We drop restatement of the definition of sunk costs. We stick to identifying the measurement rather than the concept of sunk costs by, for example, stating that nominal dollars mean dollars not adjusted for inflation.
Summary of Changes
The following table summarizes the changes this rule makes to the existing structure of our DWRR program.
Modifications to DWRR Applications
Current and continuing program Changes (applies to Element
(applies to pre-act post-2000 deep water leases)
leases only)
Eligibility (Central,
Leases in 200m or Leases in 200m or Western, and western part more water depth more water depth of Eastern Gulf of Mexico). issued before 1996. issued after 2000. Royalty-free production can Any production from Only production from come from.
the field until resources cumulative recovery identified in the volume equals the application until suspension volume. cumulative production equals the suspension volume.
[[Page 1868]]
Minimum suspension volume For fields that did For development for non-producing leases. not produce before projects, matches the Act, matches volumes designated eligible lease
in sale and lease suspension volumes documents for (17.5, 52.5, 87.5 various water MMBOE) in
depths of 200m or equivalent water greater plus 10 depths.
percent of the median value of the distribution of resources. Credit for sunk costs in For fields with pre- For development application.
Act leases that did projects, after-tax not produce before eligible costs of the application, the discovery well after-tax costs of for the project on and after discovery each participating well used in
lease. qualification. Evaluation deadline for non- 180 days for first 150 days for first producing leases.
determination, 120 determination, 120 days for a
days for a redetermination. redetermination. Threshold oil and gas price Statute sets
Original lease terms levels for lifting relief. threshold price for or Notice of Sale light sweet crude set threshold price oil and natural gas. for light sweet crude oil and natural gas.
Current and Changes (applies to discontinuing pre-act and post- Element
program (applies to 2000 deep water pre-act leases)
leases)
Discount rate used in
Same rate used on Use 10% on viability evaluation.
viability and
test, applicant profitability
chooses rate tests, applicant between 10% and 15% chooses between 10% for profitability and 15%.
test. Redetermination of field Available for new Available anytime qualification or volume by well or seismic after relief MMS.
data, 25% lower relinquished or prices, or 20%
withdrawn. higher cost.
Otherwise, for new well or seismic data, 25% lower prices, 20% higher cost, or more efficient development system. Deadline for starting
Within 1 year of Within 18 months of fabrication.
approval,
approval, extendable for up extendable for up to 1 year.
to 6 months. Correction for
Retain only half of Retain only half of overestimating cost by 20% suspension volume smaller of the or more.
granted.
granted suspension volume or the median of the distribution of resources. Minimum suspension volume None................ 10 percent of median for expansion project.
of the distribution of resources. Evaluation deadline for 180 days for first 150 days for first expansion project.
determination, 120 determination, 120 days for a
days for a redetermination. redetermination. Credit for sunk costs in None................ After-tax eligible application for expansion
costs of the project.
discovery well for the project on each participating lease.
Procedural Matters
Regulatory Planning and Review (Executive Order 12866)
The rule is a significant regulatory action under Executive Order 12866, and subject to review by the Office of Management and Budget (OMB).
-
This rule will not have an annual economic effect of $100 million or adversely affect an economic sector, productivity, jobs, the environment, or other units of government. This action describes how new deepwater leases may qualify for royalty suspensions and the circumstances under which we might grant royalty relief. Historically, we have received only a limited number of applications for royalty relief. Based upon our experience, only a small number of leases will qualify for royalty relief in any one year. The only field that has gone into production after royalty relief approval would have avoided about $7 million in royalty payments in its first year of production, had prices not exceeded the price threshold for discontinuing royalty relief. The royalty suspension options in this proposal will encourage new production from a few marginal leases, because they will sustain profitability at lower prices than they would without the relief. Royalty suspension volumes act as an incentive to production, and likely will have a beneficial effect on the offshore oil industry, domestic oil and gas supplies, and jobs. This program should increase OCS production by making production from marginal fields more profitable.
-
This rule does not create inconsistencies with other agencies' actions because it preserves the concepts and requirements from the existing rule.
-
This rule is an administrative change that will not affect current entitlements, grants, user fees, loan programs, or their recipients. This rule has no effect on these programs or rights of the programs' recipients.
-
This rule does not raise any novel legal issues, but does raise policy issues. The rule extends and supplements the existing DWRR rule. It describes conditions under which lessees have the opportunity to apply for and acquire royalty relief on post-2000 deepwater leases. Also, it eases some conditions under which lessees of pre-Act leases may seek to obtain royalty relief. In addition, the rule describes circumstances not specified in our previous regulations under which lessees may apply for royalty relief. All of these changes are consistent with the basic philosophy in the current rule of granting relief only when applicants show it is economically necessary for development.
Regulatory Flexibility (RF) Act
The Department certifies that this document will not have a significant economic effect on a substantial number of small entities under the RF Act (5 U.S.C. 601 et seq.). The provisions of this rule will not have a significant adverse economic effect on offshore lessees and operators, including those that are classified as small businesses. The rule extends the benefit of
[[Page 1869]]
discretionary royalty relief to certain OCS leases issued after November 2000 that qualify as marginally uneconomic. In any single year, we are likely to receive only a small number of royalty relief applications, which limits the number of entities the rule may affect. Based on past experience, we expect to receive between one and two applications a year for DWRR. Also, because firms initiate applications, they have the ability to avoid any adverse effects they foresee. As suggested below, the new provisions should actually lower the cost to those who choose to take advantage of the benefit offered by this regulation. An RF analysis is not required. A Small Entity Compliance Guide is not required.
Companies that extract oil, gas, or natural gas liquids or are otherwise in oil and gas exploration and development activities acquire the vast majority of leases offered at OCS lease sales and will be most affected by this rule. The Small Business Administration (SBA) defines a small business as having:
Annual revenues of $5 million or less for exploration service and field service companies.
Fewer than 500 employees for drilling companies and for companies that extract oil, gas, or natural gas liquids.
Under the North American Industry Classification System Code 211111, Crude Petroleum and Natural Gas Extraction, we estimate that a total of 1,380 firms drill oil and gas wells either onshore and/or offshore. Of these, approximately 130 companies are offshore lessees/ operators, based on current estimates. Publicly available data indicate that 39 companies qualify as large firms according to SBA criteria. Many or all of the other 91 companies may qualify as small firms with fewer than 500 employees. We cannot determine the exact number because the criteria data are not readily available. However, because of the extremely high cost and technical complexity involved in exploration and development in deep water, the vast majority of lessees/operators affected by this rule will be large companies. Of the 211 leases in deep water with a discovery or production by mid-2000, 19 large firms are the lessee/operator of 193, while 7 small firms are lessee/operator of the other 18. While that ratio suggests a 1-in-12 chance that a small operator may apply for relief, 4 of the 8 past applications we received have been from small operators. This rule continues the same basic application system we now use. Small operators do not appear to be at a disadvantage in our application process.
Provisions of the rule, in comparison with existing rules for discretionary DWRR for pre-Act leases, may reduce applicant costs in three areas:
First, new applications for DWRR will be based on a fully identified project rather than a whole, often incompletely identified, field. Consequently, applicants may need to provide less extensive geological and geophysical data. For instance, we will not require them to submit data on reservoirs that may be in the field but clearly are not part of the project. There is no sound basis for estimating the size of any savings associated with this reduced data burden because only some applications would involve potential extra reservoirs. For those that do, however, this change can reduce the amount of follow-up data we typically must request from applicants and can expedite our evaluation.
Second, applicants may no longer have to incur the cost of additional drilling or acquisition of new seismic data to request a redetermination. While significant new geologic information or price or cost changes still enable a redetermination, applicants may now also seek a redetermination upon identification of a more efficient development system. That new reason could save drilling a new deep water well at a cost of $20 million or more, or acquiring additional seismic data at a cost of about $100,000 per tract. We have received no redetermination requests. We attribute this to the fact that the DWRR program has not been active long enough to reach the redetermination stage for most of the applications we have processed.
Third, under this rule, we give successful applicants more time to initiate development than under existing rules. This added time gives operators more time to arrange financing and to negotiate contracts with suppliers. Again, there is no sound basis for estimating the size of any savings associated with this greater applicant flexibility. It is clear, however, that this change, too, cannot be considered to impose a significant adverse economic effect on a substantial number of small business entities. If anything, all three changes lessen the existing applicant cost burden.
Small Business Regulatory Enforcement Fairness Act (SBREFA)
This rule is not a major rule under 5 U.S.C. 804(2), the SBREFA. This rule: a. Does not have an annual effect on the economy of $100 million or more. This rule modifies some procedures used under the current rule, specifies how certain new deep water leases may qualify for royalty suspensions in the future, and describes circumstances not covered in the current regulations that may cause us to grant royalty relief. In general, the effect of qualifying for a royalty suspension increases production from a few marginal fields but does not change royalty collections--since without relief, no production or royalty payments would occur or be expected, so suspending them forfeits no revenue. To the extent that royalty relief encourages new production, it benefits applicants, one-half of which in the past have been small businesses. But only one of the five fields for which we have approved relief has gone into production.
-
Will not cause a major increase in costs or prices for consumers, individual industries, Federal, state, or local government agencies, or geographic regions. Oil prices are not based on the production from any one region, but are based on worldwide production and demand at any point in time. While natural gas prices are more localized, they correlate to oil prices. The rule does not change any existing leasing policies, so it should not cause prices to increase.
-
Does not have significant adverse effects on competition, employment, investment, innovation, or the ability of United States- based enterprises to compete with foreign-based enterprises. Leasing on the United States OCS is limited to citizens or residents of the United States, their associations, states, municipalities, or companies incorporated in the United States. This rule does not change that requirement, so it does not change the ability of United States firms to compete in any way.
Paperwork Reduction Act (PRA) of 1995
We examined the information collection requirements in the final rule and determined they remain unchanged from those currently approved by OMB under OMB control number 1010-0071, with a current expiration date of September 30, 2003. An 83-I submission to OMB is not required for review and approval under Sec. 3507(d) of the PRA. The PRA 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 title of the collection of information is ``30 CFR part 203, Relief or Reduction in Royalty Rates.'' Respondents include approximately 130 Federal OCS oil and gas lessees. The
[[Page 1870]]
frequency of response is on occasion. Responses to this collection of information are required to obtain or retain a benefit. MMS will protect proprietary information under applicable law and 30 CFR 203.63(b) and 250.196.
MMS uses the information to make decisions on the economic viability of leases requesting a suspension or elimination of royalty or net profit share. These decisions have substantial monetary impacts to both the lessee and the Federal Government. Royalty relief can lead to increased production of natural gas and oil, creating profits for lessees and tax revenues for the Government that they might not otherwise receive.
We estimate the total annual paperwork burden is 8,650 burden hours and $345,600 for the application and audit fee ``non-hour'' cost burdens authorized under Sec. 203.3. The following chart provides a breakdown of the components of the estimated paperwork burden of part 203 final regulations.
Application/audit fees Reporting or recordkeeping ----------------------------------------------------------------------------
requirement 30 CFR Part 203
Annual responses
Hours per response Annual burden hours
OCS Lands Act Reporting
Application--leases that generate 2 applications............. 100 hours............. 200 earnings that cannot sustain continued production (end-of-life lease).
Application 2 x $12,000 = $24,000* Audit 1 x $10,000 = $10,000
Application--apart from formal 1 Application.............. 250 hours............. 250 programs for royalty relief for marginal producing lease (expect less than 1 per year--new category).
Application 1 x $15,000 = $15,000* Audit 1 x $10,000 = $10,000
Sec. 203.55 Renounce relief
1 Letter................... 1 hour............... 1 arrangement (seldom, if ever will be used; minimal burden to prepare letter).
Sec. 203.81, 203.83 through 203.89
Burden included with applications.
...................... required reports.
OCS Lands Act Reporting
4 responses................ N/A................... 451 Subtotal.
Processing Fees = $59,000
DWRAA Reporting
Application--leases in designated 1 Application.............. 2,000 hours........... 2,000 areas of GOM deep water acquired in lease sale before 11/28/95 or after 11/28/00 and are producing (deep water expansion project).
Application 1 x $39,000 = $39,000 Audit
Application--leases in designated 1 Application.............. 2,000 hours........... 2,000 areas of deep water GOM, acquired in lease sale before 11/28/95 or after 11/28/00, that have not produced (pre-Act or post-2000 deep water leases).
Application 1 x $49,000 = $49,000* Audit 1 x $25,000 = $25,000
Application--short form to add or 1 Application.............. 40 hours.............. 40 assign pre-Act lease
Application 1 x $1,000 = $1,000 No Audit
Application--preview assessment 1 Application.............. 900 hours............. 900 (seldom if ever will be used because applicants generally opt for binding determination by MMS instead).
Application 1 x $46,600 = $46,600 No Audit
Application--apart from formal Application................ 1,000 hours........... 1,000 programs for royalty relief for marginal expansion project or marginal non-producing lease (expect less than 1 per year--new category).
Application 1 x $49,000 = $49,000 Audit 1 x $20,000 = $20,000
Redetermination.................... 1 Redetermination.......... 500 hours............. 500
Application 1 x $32,000 = $32,000* Audit 1 x $25,000 = $25,000
Sec. 203.70, 203.81, 203.90,
2 Reports.................. 20 hours.............. 40 203.91 Submit fabricator's confirmation report.
Sec. 203.70, 203.81, 203.90,
2 Reports*................. 50 hours.............. 100 203.92 2 Submit post-production development report.
Sec. 203.77 Renounce relief
1 Letter................... 1 hour................ 1 arrangement (seldom, if ever will be used; minimal burden to prepare letter).
[[Page 1871]]
Sec. 203.79(
-
Request
4 Requests................. 400 hours............. 1,600 reconsideration of MMS field designation.
Sec. 203.79(c) Request extension 1 Request.................. 2 hours............... 2 of deadline to start construction.
Sec. 203.81, 203.83 through 230.89
Burden included with applications
0 Required reports.
DWRR Act Reporting Subtotal.... 16 Responses............... N/A................... 8,183
Processing Fees = $286,600
Recordkeeping Burden
Sec. 203.91 Retain supporting cost 2 Record-keepers........... 8 hours............... 16 records for post-production development/fabrication reports (records retained as usual/ customary business practice; minimal burden to make available at MMS request).
In addition, under Sec. 203.81, a report prepared by an independent CPA must accompany the application and post-production report (except expansion project, short form, and preview assessment applications are excluded). The OCS Lands Act applications will require this report only once; the DWRR Act applications will require this report at two stages--with the application and with the post-production development report for successful applicants. We estimate an average cost for a report is $45,000, and that seven CPA certifications per year will be necessary if the applications are approved. The total estimated annual ``non-hour'' cost burden for this requirement is $315,000 ($45,000 per certification x 7 CPA certifications = $315,000).
Federalism (Executive Order 13132)
Under Executive Order 13132, this rule does not have Federalism implications. The rule neither substantially nor directly affects the relationship between the Federal and State Governments. This rule affects the collection of royalty revenues from deepwater lessees in the GOM, all of which is outside State jurisdiction. States have no role in this activity with or without this rule. This rule does not impose costs on States or localities. States and local governments play no part in the administration of the DWRR program.
Takings Implications Assessment (Executive Order 12630)
Under Executive Order 12630, the rule does not have significant Takings implications. A Takings Implication Assessment is not required because the rule would not take away or restrict a bidder's right to acquire or develop OCS leases.
Energy Supply, Distribution, or Use (Executive Order 13211)
This rule is a significant rule and is subject to review by the Office of Management and Budget under Executive Order 12866. The rule does not have a significant effect on energy supply, distribution, or use because its promotes, rather than adversely affects, the production of additional oil and gas from the OCS. It promotes energy supply from marginal domestic sources by broadening applicability of the process by which we may lower costs for those producers.
Unfunded Mandates Reform Act (UMRA)
This rule does not impose an unfunded mandate on State, local, or tribal governments or the private sector of more than $100 million per year. The rule does not have a significant or unique effect on State, local, or tribal governments. The rule modifies some procedures in the existing regulation, describes how certain new leases may qualify for royalty suspensions, and specifies circumstances that might cause us to grant royalty relief outside our formal programs. None of these changes involve state, local, or tribal mandates. A statement containing additional UMRA (2 U.S.C. 1531 et seq.) information is not required.
Civil Justice Reform (Executive Order 12988)
Under Executive Order 12988, the Office of the Solicitor has determined that this rule does not unduly burden the judicial system and meets the requirements of sections 3(a) and 3(b)(2) of the Order.
National Environmental Policy Act (NEPA) of 1969
This rule does not constitute a major Federal action significantly affecting the quality of the human environment. A detailed statement under the NEPA is not required.
Government-to-Government Relationship With Tribes
Pursuant to the President's memorandum of April 29, 1994, ``Government-to-Government Relations with Native American Tribal Governments'' (59 FR 22951) and 512 DM 2, we have determined that there are no effects from this action on federally recognized Indian tribes.
List of Subjects in 30 CFR Part 203
Continental shelf, Government contracts, Indians-lands, Minerals royalties, Oil and gas exploration, Public lands-mineral resources, Reporting and recordkeeping requirements, Sulphur.
Dated: December 18, 2001. James E. Cason, Acting Deputy Secretary.
For the reasons stated in the preamble, the Minerals Management Service (MMS) amends 30 CFR part 203 as follows:
PART 203--RELIEF OR REDUCTION IN ROYALTY RATES
-
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.
[[Page 1872]]
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.
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Section 203.0 is amended by removing the definition of ``Sunk costs,'' adding definitions for ``Development project,'' ``Royalty suspension (RS) lease,'' ``Sunk costs for an authorized field,'' and ``Sunk costs for an expansion or development project'' in alphabetical order, and revising the definitions for ``Authorized field,'' ``Eligible lease,'' ``Expansion project,'' ``Fabrication (or start of construction),'' ``New production,'' ``Pre-Act lease,'' and ``Redetermination,'' to read as follows:
Sec. 203.0 What definitions apply to this part?
Authorized field means a field:
(1) Located in a water depth of at least 200 meters and in the Gulf of Mexico (GOM) west of 87 degrees, 30 minutes West longitude;
(2) That includes one or more pre-Act leases; and
(3) From which no current pre-Act lease produced, other than test production, before November 28, 1995; * * * * *
Development project means a project to develop one or more oil or gas reservoirs located on one or more contiguous leases that:
(1) Were issued in a sale held after November 28, 2000;
(2) Are located in a water depth of at least 200 meters and in the GOM wholly west of 87 degrees, 30 minutes West longitude; and
(3) Have had no production (other than test production) before the current application for royalty relief. * * * * *
Eligible lease means a lease that:
(1) Is issued as part of an OCS lease sale held after November 28, 1995, and before November 28, 2000;
(2) Is located in the Gulf of Mexico in water depths of 200 meters or deeper;
(3) Lies wholly west of 87 degrees, 30 minutes West longitude; and
(4) Is offered subject to a royalty suspension volume.
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 significantly increase the ultimate recovery of resources from one or more reservoirs that have not produced on a pre-Act lease or a lease issued in a sale held after November 28, 2000. A significant increase does not simply extend recovery from reservoirs already in production. For a pre-Act lease, the expansion project must also involve a substantial capital investment (e.g., fixed-leg platform, subsea template and manifold, tension-leg platform, multiple well project, etc.). For a lease issued after November 28, 2000, the expansion project must involve a new well drilled into a reservoir that has not previously produced. In all cases, all leases in an expansion project must be wholly located in a water depth of at least 200 meters and in the GOM wholly west of 87 degrees, 30 minutes West longitude.
Fabrication (or start of construction) means evidence of an irreversible commitment to a concept and scale of development. Evidence includes copies of a binding contract between you (as applicant) and a fabrication yard, a letter from a fabricator certifying that continuous construction has begun, and a receipt for the customary down payment. * * * * *
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 additional production resulting from new lease-development activities on a lease issued in a sale after November 28, 2000, or a current pre-Act lease under a DOCD or a Supplement approved by the Secretary of the Interior after November, 28, 1995. * * * * *
Pre-Act lease means a lease that:
(1) Results from a sale held before November 28, 1995;
(2) Is located in the GOM in water depths of 200 meters or deeper; and
(3) Lies wholly west of 87 degrees, 30 minutes West longitude. * * * * *
Redetermination means our reconsideration of our determination on royalty relief because you request it after:
(1) We have rejected your application;
(2) We have granted relief but you want a larger suspension volume;
(3) We withdraw approval; or
(4) You renounce royalty relief. * * * * *
Royalty suspension (RS) lease means a lease that:
(1) Is issued as part of an OCS lease sale held after November 28, 2000;
(2) Is in locations or planning areas specified in a particular Notice of OCS Lease Sale offering that lease; and
(3) Is offered subject to a royalty suspension specified in a Notice of OCS Lease Sale published in the Federal Register.
Sunk costs for an authorized field means the after-tax eligible costs that you (not third parties) incur for exploration, development, and production from the spud date of the first discovery on the field to the date we receive your complete application for royalty relief. The discovery well must be qualified as producible under part 250, subpart A of this title. Sunk costs include the rig mobilization and material costs for the discovery well that you incurred before its spud date.
Sunk costs for an expansion or development project means the after- tax eligible costs that you (not third parties) incur for only the first well that encounters hydrocarbons in the reservoir(s) included in the application and that meets the producibility requirements under part 250, subpart A of this chapter on each lease participating in the application. Sunk costs include rig mobilization and material costs for the discovery wells that you incurred before their spud dates. * * * * *
-
Section 203.2 is revised to read as follows:
Sec. 203.2 How can I get royalty relief?
We may reduce or suspend royalties for Outer Continental Shelf (OCS) leases or projects that meet the criteria in the following table.
Then we may grant
If you have a lease . . . And if you . . .
you . . .
(
-
-
With earnings that cannot Would abandon A reduced royalty sustain production (i.e., End- otherwise
rate on current of-life lease).
potentially
monthly recoverable
production and a resources but higher royalty seek to increase rate on production by additional operating beyond monthly the point at
production. (See which the lease Secs. 203.50 is economic under through 203.56.) the existing royalty rate.
[[Page 1873]]
(b) Located in a designated GOM Are producing and A royalty deep water area, and acquired seek to increase suspension for in a lease sale before November ultimate resource additional 28, 1995, or after November 28, recovery from one production large 2000, and you propose in a DOCD or more
enough to make or supplement to expand
reservoirs not the project production significantly.
previously or economic. (See currently
Secs. 203.60 producing on the through 203.79.) field or lease, not simply extend recovery of reservoirs that already produced. (Expansion project). (c) Located in a designated GOM Are on a field A royalty deep water area and acquired in from which no suspension for a a lease sale held before
current pre-Act minimum November 28, 1995 (Pre-Act
lease produced production volume lease).
(other than test plus any production)
additional volume before November needed to make 28, 1995
the field (Authorized
economic. (See field).
Secs. 203.60 through 203.79.) (d) Located in a designated GOM Have not produced A royalty deep water area and acquired in and can
suspension for a a lease sale held after
demonstrate that minimum November 28, 2000.
the suspension production volume volume, if any, plus any in your lease is additional volume not enough to needed to make make development your project economic
economic. (See (Development
Secs. 203.60 project).
through 203.79.) (e) Where royalty relief would Are not eligible A royalty recover significant additional to apply for end- modification in resources or, in certain areas of-life or deep size, duration, of the GOM, would enable
water royalty or form that development.
relief, but show makes your lease us you meet
or project certain
economic. (See elligibility
Sec. 203.80.) conditions.
-
Section 203.4 is revised to read as follows:
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 of this part apply in different situations.
(
-
-
We require the information elements indicated by an X in the following table and described in Secs. 203.51, 203.62, and 203.81 through 203.89 for applications for royalty relief.
Deep water End-of- ------------------------------------------ Information elements
life Expansion Pre-act Development lease
project lease
project
(1) Administrative information report.....................
X
X
X
X (2) Net revenue and relief justification report
X (prescribed format)...................................... (3) Economic viability and relief justification report
X
X
X (Royalty Suspension Viability Program (RSVP) model inputs justified with Geological and Geophysical (G&G), Engineering, Production, & Cost reports)................. (4) G&G report............................................
X
X
X (5) Engineering report....................................
X
X
X (6) Production report.....................................
X
X
X (7) Deep water cost report................................
X
X
X
(b) We require the confirmation elements indicated by an X in the following table and described in Secs. 203.70, 203.81 and 203.90 through 203.91 to retain royalty relief.
Deep water End-of- ------------------------------------------ Confirmation elements
life Expansion Pre-act Development lease
project lease
project
(1) Fabricator's confirmation report......................
X
X
X (2) Post-production development report approved by an
X
X
X independent certified public accountant (CPA)............
(c) The following table indicates by an X, and Secs. 203.50, 203.52, 203.60 and 203.67 describe, the prerequisites for our approval of your royalty relief application.
Deep water End-of- ------------------------------------------ Approval conditions
life
Pre-act Development lease Expansion lease
project
(1) At least 12 of the last 15 months have the required
X level of production...................................... (2) Already producing.....................................
X (3)A producible well into a reservoir that has not
X
X
X produced before.......................................... (4) Royalties for qualifying months exceed 75% of net
X revenue (NR)............................................. (5) Substantial investment on a pre-Act lease (e.g.,
X platform, subsea template)...............................
[[Page 1874]]
(6) Determined to be economic only with relief............
X
X
X
(d) The following table indicates by an X, and Secs. 203.52 and 203.74 through 203.75 describe, the prerequisites for a redetermination of our royalty relief decision.
Deep water End-of- ------------------------------------------ Redetermination conditions
Life Expansion Pre-act Development lease
project lease
project
(1) After 12 months under current rate, criteria same as
X for approval............................................. (2) For material change in geologic data, prices, costs,
X
X
X or available technology..................................
(e) The following table indicates by an X, and Secs. 203.53 and 203.69 describe, the characteristics of approved royalty relief.
Deep water End-of- ------------------------------------------ Relief rate and volume, subject to certain conditions life Expansion Pre-act Development lease
project lease
project
(1) One-half pre-application effective lease rate on the
X 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........................ (2) Qualifying amount is the average monthly production
X for 12 qualifying months................................. (3) Zero royalty rate on the suspension volume and the
X
X
X original lease rate on additional production............. (4) Suspension volume is at least 17.5, 52.5 or 87.5
X million barrels of oil equivalent (MMBOE)................ (5) Suspension volume is at least the minimum set in the
X
X Notice of Sale, the lease, or the regulations............ (6) Amount needed to become economic......................
X
X
X
(f) The following table indicates by an X, and Secs. 203.54 and 203.78 describe, circumstances under which we discontinue your royalty relief.
Deep water End-of- ------------------------------------------ Full royalty resumes when
life Expansion Pre-act Development lease
project lease
project
(1) Average NYMEX price for last 12 months is at least 25
X percent above the average for the qualifying months...... (2) Average NYMEX price for last calendar year exceeds $28/
X
X bbl or $3.50/mcf, escalated by the gross domestic product (GDP) deflator since 1994................................ (3) Average prices for designated periods exceed levels we
X
X specify in the Notice of Sale or the lease...............
(g) The following table indicates by an X, and Secs. 203.55 and 203.76 through 203.77 describe, circumstances under which we end or reduce royalty relief.
Deep water End-of- ------------------------------------------ Relief withdrawn or reduced
life Expansion Pre-act Development lease
project lease
project
(1) If recipient requests.................................
X
X
X
X (2) Lease royalty rate is at the effective rate for 12
X consecutive months....................................... (3) Conditions occur that we specified in the approval
X letter in individual cases............................... (4) Recipient does not submit post-production report that
X
X
X compares expected to actual costs........................
[[Page 1875]]
(5) Recipient changes development system..................
X
X
X (6) Recipient excessively delays starting fabrication.....
X
X
X (7) Recipient spends less than 80 percent of proposed pre-
X
X
X production costs prior to start of production............ (8) Amount of relief volume is produced...................
X
X
X
-
Section 203.60 is revised to read as follows:
Sec. 203.60 Who may apply for deep water royalty relief?
You may apply for royalty relief under Secs. 203.61(b) and 203.62 if:
(
-
-
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 pre-Act lease to a field (as defined in Sec. 203.0); and
(c) You either:
(1) Hold a pre-Act lease on an authorized field (as defined in Sec. 203.0) or
(2) Propose an expansion project (as defined in Sec. 203.0) or
(3) Propose a development project (as defined in Sec. 203.0).
-
In Sec. 203.62, the introductory sentence and paragraph (c) are revised to read as follows:
Sec. 203.62 How do I apply for relief?
You must send a complete application and the required fee to the MMS Regional Director for the GOM. * * * * *
(c) Sections 203.81, 203.83, and 203.85 through 203.89 describe what these reports must include. The MMS regional office for the GOM will guide you on the format for the required reports, and we encourage you to contact this office prior to preparing your application for this guidance.
-
In Sec. 203.63, the following changes are made:
-
Paragraphs (a), (b), and (c) following the introductory paragraph are redesignated paragraphs (a)(1), (a)(2), and (a)(3).
-
The introductory paragraph is redesignated (a) and is revised to read as set forth below.
-
A new paragraph (b) is added as set forth below.
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 (a)(3) of this section and Sec. 203.64. However, we will evaluate all acreage that may eventually become part of the authorized field. Therefore, if you have any other leases that you believe may eventually be part of the authorized field, you must submit data for these leases according to Sec. 203.81. * * * * *
(b) If your application seeks only relief for a development project or an expansion project, your application does not have to include all leases in the field.
-
In Sec. 203.64, the section heading and the first sentence in the introductory paragraph are revised to read as follows:
Sec. 203.64 How many applications may I file on a field or a development project?
You may file one complete application for royalty relief during the life of the field or for a development project or an expansion project designed to produce a reservoir or set of reservoirs. * * * * * * * *
-
In Sec. 203.65, paragraph (b) is revised to read as follows:
Sec. 203.65 How long will MMS take to evaluate my application?
* * * * *
(b) We will evaluate your first application on a field within 180 days, evaluate your first application on a development project or an expansion project within 150 days and evaluate a redetermination under Sec. 203.75 within 120 days after we determine that it is complete. * * * * *
-
Section 203.66 revised to read as follows:
Sec. 203.66 What happens if MMS does not act in the time allowed?
If we do not act within the timeframes established under Sec. 203.65, you get royalty relief according to the following table.
And we do not If you apply for royalty relief decide within the As long as you for
time specified
(
-
-
An authorized field......... You get the
Abide by Secs. minimum
203.70 and suspension
203.76. volumes specified in Sec. 203.69. (b) An expansion project........ You get a royalty Abide by Secs. suspension for 203.70 and the first year of 203.76. production. (c) A development project....... You get a royalty Abide by Secs. suspension for 203.70 and initial
203.76. production for the number of months that a decision is delayed beyond the stipulated timeframes set by Sec. 203.65, plus all the royalty suspension volume for which you qualify.
[[Page 1876]]
-
Section 203.67 is revised to read as follows:
Sec. 203.67 What economic criteria must I meet to get royalty relief on an authorized field or project?
We will not approve applications if we determine that royalty relief cannot make the field, development project, or expansion project economically viable. Your field or project must be uneconomic while you are paying royalties and must become economic with royalty relief.
-
In Sec. 203.68, paragraph (b) is revised to read as follows:
Sec. 203.68 What pre-application costs will MMS consider in determining economic viability?
* * * * *
(b) We will consider sunk costs according to the following table.
We will
When determining
(1) Include sunk costs................. Whether a field that includes a pre-Act lease which has not produced, other than test production, before the application or redetermination submission date needs relief to become economic. (2) Not include sunk costs............. Whether an authorized field, a development project, or an expansion project can become economic with full relief (see Sec. 203.67). (3) Not include sunk costs............. How much suspension volume is necessary to make the field, a development project, or an expansion project economic (see Sec. 203.69(c)). (4) Include sunk costs for the project Whether a development project discovery well on each lease.
or an expansion project needs relief to become economic.
-
In Sec. 203.69, the introductory paragraph and paragraphs (b) through (e) are revised, and paragraph (f) is added to read as follows:
Sec. 203.69 If my application is approved, what royalty relief will I receive?
If we approve your application, subject to certain conditions, we will not collect royalties on a specified suspension volume for your field, development project, or expansion project. Suspension volumes include volumes allocated to a lease under an approved unit agreement, but exclude any volumes of production that are not normally royalty- bearing under the lease or the regulations of this chapter (e.g., fuel gas). * * * * *
(b) For development projects, any relief we grant applies only to project wells and replaces the royalty suspension volume with which we issued your lease. If your project is economic given the royalty suspension volume with which we issued your lease, we will reject the application. Otherwise, the minimum royalty suspension volumes are as shown in the following table:
The minimum royalty For
suspension volume is
Plus
(1) RS leases................. A volume equal to the 10 percent of combined royalty
the median of suspension volumes the (or the volume
distribution of equivalent based on known the data in your
recoverable approved application resources upon for other forms of which we based royalty suspension) approval of with which we issued your the leases
application participating in the from all application that have reservoirs or plan a well into a included in the reservoir identified project. in the application. (2) Other deep water leases A volume equal to 10 issued in sales after
percent of the median November 28, 2000.
of the distribution of known recoverable resources upon which we based approval of your application from all reservoirs included in the project.
(c) If your application includes pre-Act or eligible leases in different categories of water depth, we apply the minimum royalty suspension volume for the deepest such lease then assigned to the field. We base the water depth and makeup of a field on the water-depth delineations in the ``Lease Terms and Economic Conditions'' map and the ``Field Names Master List'' documents and updates in effect at the time your application is deemed complete. These publications are available from the MMS Regional Office for the GOM.
(d) You will get a royalty suspension volume above the minimum if we determine that you need more to make the field or development project economic.
(e) For expansion projects, the minimum royalty suspension volume equals 10 percent of the median of the distribution of known recoverable resources upon which we based approval of your application from all reservoirs included in your project plus any suspension volumes required under Sec. 203.66. If we determine that your expansion project may be economic only with more relief, we will determine and grant you the royalty suspension volume necessary to make the project economic.
(f) The royalty suspension volume applicable to specific leases will continue through the end of the month in which cumulative production reaches that volume. You must calculate cumulative production from all the leases in the authorized field or project that are entitled to share the royalty suspension volume.
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Section 203.70 is revised to read as follows:
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, 203.90, and 203.91 describe what these reports must include. The MMS regional office for the GOM will prescribe the formats.
[[Page 1877]]
Due date Required report
When due to MMS extensions
(
-
-
Fabricator's confirmation Within 18 months MMS Director may report.
after approval of grant you an relief.
extension under Sec. 203.79(c) for up to 6 months. (b) Post-production report...... Within 120 days With acceptable after the start justification of production from you, MMS that is subject Regional Director to the approved for the GOM may royalty
extend due date suspension volume. up to 30 days.
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In Sec. 203.71, the introductory paragraph and paragraphs (a) through (c) are revised to read as follows:
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 we issued the lease, when we assigned it to the field, and whether we award the volume suspension by an approved application or establish it in the lease terms, as prescribed in this section.
(
-
-
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 leases in the field that participate in the application until their cumulative production equals the approved volume. The following conditions also apply:
If . . .
Then . . .
And . . .
(1) We assign an eligible lease We will not change The assigned to your field after we approve your field's
lease(s) may relief.
royalty
share in any suspension volume. remaining royalty relief. (2) We assign a pre-Act or post- We will not change The assigned November 2000 deep water lease your field's
lease(s) may to your field after we approve royalty
share in any your application.
suspension volume. remaining royalty relief by filing the short-form application specified in Sec. 203.83 and authorized in Sec. 203.82. An assigned RS lease also gets any portion of its royalty suspension volume remaining even after the field has produced the approved relief volume. (3) We assign another lease(s) We will change (i) You toll the that you operate to your field your field's
time period for while we are evaluating your minimum
evaluation until application.
suspension volume you modify your if the assigned application to be lease is a pre- consistent with Act or eligible the new field; lease entitled to (ii) We have an a larger minimum additional 60 or automatic
days to review suspension volume. the new information; and (iii) The assigned lease(s) shares the royalty suspension we grant to the new field. If you do not agree to toll, we will have to reject your application due to incomplete information. But, an eligible lease we assigned to the field kept its automatic suspension volume. (4) We assign another operator's We will change (i) You both toll lease to your field while we your field's
the time period are evaluating your application. minimum
for evaluation suspension volume until both of you provided the
modify your assigned lease application to be joins the
consistent with application and the new field; is entitled to a (ii) We have an larger minimum additional 60 suspension volume. days to review the new information; and (iii) The assigned lease(s) shares the royalty suspension we grant to the new field. If you (the original applicant) do not agree to toll, the other operator's lease retains any suspension volume it has or may share in any relief that we grant by filing the short form application specified in Sec. 203.83 and authorized in Sec. 203.82. (5) We reassign a well on a pre- The past
The past Act, eligible, or post-November production from production from 2000 deep water lease to
the well counts that well will another field.
toward the
not count toward royalty
any royalty suspension volume suspension volume of the field to granted to the which we assigned field from which the well.
we reassigned it.
(b) If your authorized field has a royalty suspension volume established under Sec. 260.111 of this title (i.e., a field with a pre- Act lease where an eligible lease starts production first), we will suspend payment of royalties on production from all eligible leases in the field until their cumulative production equals the established volume. The following conditions also apply:
[[Page 1878]]
If . . .
Then . . .
And . . .
(1) We assign another eligible Your field's
The assigned lease lease to your field.
royalty
may share in any suspension volume remaining royalty does not change. relief. (2) We assign an RS lease to Your field's
The assigned lease your field.
royalty
gets only the suspension volume volume suspension does not change. with which we issued it, and its production volume counts against the field's royalty suspension volume. (3) We assign a pre-Act lease or Your field's
We assign lease a lease issued after November royalty
shares none of 2000 without royalty suspension suspension volume the volume to your field.
does not change. suspension, and its production does not count as part of the suspension volume. (4) A pre-Act or post-November Your field's
(i) All leases in 2000 deep water lease applies royalty
the field share (along with the other leases in suspension volume the royalty the field) and qualifies
may increase or suspension volume (subject to any pre-existing stay the same, if we approve the suspension volumes) for royalty but will not
application; or relief under Secs. 203.67 and diminish.
(ii) The eligible 203.69.
or RS leases in the field keep their respective volumes if we reject the application.
(c) When a project has more than one lease, the royalty suspension volume for each lease equals that lease's actual production from the project (or production allocated under an approved unit agreement) until total production for all leases in the project equals the project's approved royalty suspension volume. * * * * *
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In Sec. 203.74, the introductory paragraph is revised, paragraphs (b) and (c) are redesignated as paragraphs (c) and (d) and revised, and a new paragraph (b) is added to read as follows:
Sec. 203.74 When will MMS reconsider its determination?
You may request a redetermination after we withdraw approval or after you renounce royalty relief, unless we withdraw approval due to your providing false or intentionally inaccurate information. Under certain conditions you may also request a redetermination if we deny your application or if you want your approved royalty suspension volume to change. In these instances, to be eligible for a redetermination, at least one of the following four conditions must occur. * * * * *
(b) You demonstrate in your new application that the technology that most efficiently develops this field or lease was not considered or deemed feasible in the original application. Your newly proposed technology must improve the profitability, under equivalent market conditions, of the field or lease relative to the development system proposed in the prior application.
(c) Your current reference price decreases by more than 25 percent from your base reference price as calculated under this paragraph.
(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 light sweet crude oil and natural gas for the 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.
(d) 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.
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In Sec. 203.76, paragraphs (a), (b), and (c) are revised to read as follows:
Sec. 203.76 When might MMS withdraw or reduce the approved size of my relief?
* * * * *
(
-
-
You change the type of development system proposed in your application (e.g., change from a fixed platform to floating production system, or from 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 within18 months of the date we approved your application, unless the MMS Director grants you an extension under Sec. 203.79(c). If you start building the proposed system and then suspend its construction before completion, and you do not restart continuous building of the proposed system within 18 months of our approval, we will withdraw the relief we granted.
(c) Your actual development costs are less than 80 percent of the eligible development costs estimated in your application's most likely scenario, and you do not report that fact in your post-production development report (Sec. 203.70). Development costs are those expenditures defined in Sec. 203.89(b) incurred between the application submission date and start of production. If you report this fact in the post-production development report, you may retain the lesser of 50 percent of the original royalty suspension volume or 50 percent of the median of the distribution of the potentially recoverable resources anticipated in your application. * * * * *
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Section 203.77 is revised to read as follows:
Sec. 203.77 May I voluntarily give up relief if conditions change?
Yes, by sending a letter to that effect to the MMS Regional Director for the GOM.
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In Sec. 203.78, the introductory paragraph, and paragraphs (a)(1), (b)(1) and (f) are revised to read as follows:
Sec. 203.78 Do I keep relief if prices rise significantly?
If prices rise above a base price for light sweet crude oil or natural gas, set by statute for pre-Act leases, indicated in your original lease agreement or Notice of Sale for post-November 2000 deep water leases, you must pay full royalties as prescribed in this section. For post-November 2000 deepwater leases, price thresholds apply on a lease basis, so different leases on the same field, development project, or expansion
[[Page 1879]]
project may have different price thresholds.
(a) * * *
(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 March 31 of the current calendar year, and * * * * *
(b) * * *
(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 March 31 of the current calendar year, and * * * * *
(f) We change the prices referred to in paragraphs (a), (b), and (d) of this section periodically. For pre-Act leases, these prices change during each calendar year after 1994 by the percentage that the implicit price deflator for the gross domestic product changed during the preceding calendar year. For post-November 2000 deepwater leases, these prices change as indicated in the lease instrument or in the Notice of Sale under which we issued the lease.
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Section 203.80 is added to read as follows:
Sec. 203.80 When can I get royalty relief if I am not eligible for end-of-life or deep water royalty relief?
We may grant royalty relief when it serves the statutory purposes summarized in Sec. 203.1, and our formal relief programs provide inadequate encouragement to increase production or development. Unless your lease lies wholly west of 87 degrees, 30 minutes West longitude in the Gulf of Mexico, your lease must be producing to qualify for relief. Before you may apply for royalty relief apart from our end-of-life or deepwater programs, we must agree that your lease or project has two or more of the following characteristics:
(
-
-
The lease has produced for a substantial period and the lessee can recover significant additional resources. Significant additional resources means enough to allow production for at least a year more than would be profitable without royalty relief.
(b) Valuable facilities (e.g., a platform or pipeline that would be removed upon lease relinquishment) exist that we do not expect a successor lessee to use. If the facilities are located off the lease, their preservation must depend on continued production from the lease applying for royalty relief. We will only consider an allocable share of costs for off-lease facilities in the relief application.
(c) A substantial risk exists that no new lessee will recover the resources.
(d) The lessee made major efforts to reduce operating costs too recently to use the formal program for royalty relief (e.g., recent significant change in operations).
(e) Circumstances beyond the lessee's control, other than water depth, preclude reliance on one of the existing royalty relief programs.
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In Sec. 203.81, paragraphs (a) and (c) are revised to read as follows:
Sec. 203.81 What supplemental reports do royalty relief applications require?
(
-
-
You must send us the supplemental reports, indicated in the following table by an X, that apply to your field. Sections 203.83 through 203.91 describe these reports in detail.
Deep water End-of- ------------------------------------------ Required reports
life Expansion Pre-act Development lease
project lease
project
(1) Administrative information Report.....................
X
X
X
X (2) Net revenue & relief justification report.............
X (3) Economic viability & relief justification report (RSVP
X
X
X model imputs justified by other required reports)........ (4) G&G report............................................
X
X
X (5) Engineering report....................................
X
X
X (6) Production report.....................................
X
X
X (7) Deep water cost report................................
X
X
X (8) Fabricator's confirmation report......................
X
X
X (9) Post-production development report....................
X
X
X
* * * * *
(c) With your application and post-production development report, you must submit an additional report prepared by an independent 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 information conform to our most recent guidelines on royalty relief. This means the data and information must--
(i) Include only eligible costs that are incurred during the qualification months; and
(ii) Be shown in the proper format. * * * * *
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In Sec. 203.83, paragraph (c) is revised to read as follows:
Sec. 203.83 What is in an administrative information report?
* * * * *
(c) Well number, API number, location, and status of each well that has been drilled on the field or lease or project (not required for non-oil and gas leases); * * * * *
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In Sec. 203.86, the following changes are made:
-
The word ``and'' is removed at the end of paragraph (b)(6).
-
The ``.'' is removed and ``; and'' is added at the end of paragraph (b)(7).
-
Paragraph (b)(8) is added.
-
Paragraph (c)(4) is revised.
-
The word ``and'' is removed at the end of paragraph (d)(6).
-
The ``.'' is removed and ``; and'' is added at the end of paragraph (d)(7)
-
Paragraph (d)(8) is added.
The revisions and additions read as follows:
Sec. 203.86 What is in a G&G report?
* * * * *
(b) * * *
(8) A table listing the wells and completions, and indicating which sands and fault blocks will be targeted for completion or recompletion.
(c) * * *
(4) An explanation for excluding the reservoirs you are not planning to develop.
(d) * * *
[[Page 1880]]
(8) Reserve or resource distribution by reservoir. * * * * *
-
-
In Sec. 203.87, paragraphs (a)(1) and (d) are revised to read as follows:
Sec. 203.87 What is in an engineering report?
* * * * *
(a) * * *
(1) Its size along with basic design specifications and drawings; and * * * * *
(d) A discussion of any plans for multi-phase development which includes the conceptual basis for developing in phases and goals or milestones required for starting later phases. * * * * *
-
In Sec. 203.89, paragraph (a) is revised to read as follows:
Sec. 203.89 What is in a deep water cost report?
* * * * *
(
-
-
Sunk costs. Report sunk costs in dollars not adjusted for inflation and only if you have documentation. * * * * *
-
In Sec. 203.91, a new last sentence is added to read as follows:
Sec. 203.91 What is in a post-production development report?
* * * Also, you must have this report certified by an independent CPA according to Sec. 203.81(c).
[FR Doc. 02-438Filed1-14-02; 8:45 am]
BILLING CODE 4310-MR-P
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