saturated (R) and the resistivity of the undisturbed formation (R1), and

(iv) The 5-inch porosity logs show pay zones and pay counts and labeled points used in establishing reservoir porosity or labeled points showing values used in calculating reservoir porosity such as bulk density or transit time;

(2) Digital copies of all well logs spudded before December 1, 1995;

(3) Core data, if available;

(4) Well correlation sections; (5) Pressure data;

(6) Production test results; and (7)

Pressure-volume-temperature

analysis, if available.

(c) Map interpretations which includes for each reservoir in the field:

(1) Structure maps consisting of top and base of sand maps showing well and seismic shot point locations;

(2) Isopach maps for net sand, net oil, net gas, all with well locations;

(3) Maps indicating well surface and bottom hole locations, location of development facilities, and shot points; and

(4) Identification of reservoirs not contemplated for development.

(d) Reservoir-specific data which includes:

(1) Probability of reservoir occurrence with hydrocarbons;

(2) Probability the hydrocarbon in the reservoir is all oil and the probability it is all gas;

(3) Distributions or point estimates (accompanied by explanations of why distributions less appropriately reflect the uncertainty) for the parameters used to estimate reservoir size, i.e., acres and net thickness;

(4) Most likely values for porosity, salt water saturation, volume factor for oil formation, and volume factor for gas formation;

(5) Distributions or point estimates (accompanied by explanations of why distributions less appropriately reflect the uncertainty) for recovery efficiency (in percent) and oil or gas recovery (in stock-tank-barrels per acre-foot or in thousands of cubic feet per acre foot);

(6) A gas/oil ratio distribution or point estimate (accompanied by explanations of why distributions less appro

priately reflect the uncertainty) for each reservoir; and

(7) A yield distribution or point estimate (accompanied by explanations of why distributions less appropriately reflect the uncertainty) for each gas reservoir.

(e) Aggregated reserve and resource data which includes:

(1) The aggregated distributions for reserves and resources (in BOE) and oil fraction for your field computed by the resource module of our RSVP model;

(2) A description of anticipated hydrocarbon quality (i.e., specific gravity); and

(3) The ranges within the aggregated distribution for reserves and resources that define the development and production scenarios presented in the engineering and production reports. Typically there will be three ranges specified by two positive reserve and resource points on the aggregated distribution. The range at the low end of the distribution will be associated with the conservative development and production scenario; the middle range will be related to the most likely development and production scenario; and, the high end range will be consistent with the optimistic development and production scenario.

§ 203.87 What is in an engineering report?

This report defines the development plan and capital requirements for the economic evaluation and must contain the following elements.

(a) A description of the development concept (e.g., tension leg platform, fixed platform, floater type, subsea tieback, etc.) which includes:

(1) Its size and

(2) The construction schedule. (b) An identification of planned wells which includes:

(1) The number;

(2) The type (platform, subsea, vertical, deviated, horizontal); (3) The well depth;

(4) The drilling schedule;

(5) The kind of completion (single, dual, horizontal, etc.); and

(6) The completion schedule.

(c) A description of the production system equipment which includes:

(1) The production capacity for oil and gas and a description of limiting component(s);

(2) Any unusual problems (low gravity, paraffin, etc.);

(3) All subsea structures; (4) All flowlines; and

(5) Schedule for installing the production system.

(d) A discussion of any plans for multi-phase development which includes:

(1) The conceptual basis for developing in phases and goals or milestones required for starting later phases; and

(2) An explanation for excluding the reservoirs you are not planning to develop.

(e) A set of development scenarios consisting of activity timing and scale associated with each of up to three production profiles (conservative, most likely, optimistic) provided in the production report for your field (§ 203.88). Each development scenario and production profile must denote the likely events should the field size turn out to be within a range represented by one of the three segments of the field size distribution. If you send in fewer than three scenarios, you must explain why fewer scenarios are more efficient

across the whole field size distribution.

§ 203.88 What is in a production report?

This report supports your development and production timing and product quality expectations and must contain the following elements.

(a) Production profiles by well completion and field that specify the actual and projected production by year for each of the following products: oil, condensate, gas, and associated gas. The production from each profile must be consistent with a specific level of reserves and resources on the aggregated distribution of field size.

(b) Production drive mechanisms for each reservoir.

§ 203.89 What is in a deep water cost report?

This report lists all actual and projected costs for your field, must explain and document the source of each cost estimate, and must identify the following elements.

(a) Sunk cost, which are all your eligible post-discovery exploration, development, and production expenses (no third party costs), and also include the eligible costs of the discovery well on the field. Report them in nominal dollars and only if you have documentation. We count sunk costs in an evaluation (specified in §203.68) as after-tax expenses, using nominal dollar amounts.

(b) Appraisal, delineation and development costs. Base them on actual spending, current authorization for expenditure, engineering estimates, or analogous projects. These costs cover: (1) Platform well drilling and average depth;

(2) Platform well completion;

(3) Subsea well drilling and average depth;

(4) Subsea well completion;

(5) Production system (platform); and (6) Flowline fabrication and installation.

(c) Production costs based on historical costs, engineering estimates, or analogous projects. These costs cover: (1) Operation;

(2) Equipment; and

(3) Existing royalty overrides (we will not use the royalty overrides in evaluations).

(d) Transportation costs, based on historical costs, engineering estimates, or analogous projects. These costs

Cover:

(1) Oil or gas tariffs from pipeline or tankerage;

(2) Trunkline and tieback lines; and (3) Gas plant processing for natural gas liquids.

(e) Abandonment costs, based on historical costs, engineering estimates, or analogous projects. You should provide the costs to plug and abandon only wells and to remove only production systems for which you have not incurred costs as of the time of application submission. You should also include a point estimate or distribution of prospective salvage value for all potentially reusable facilities and materials, along with the source and an explanation of the figures provided.

(f) A set of cost estimates consistent with each one of up to three field-development scenarios and production

profiles (conservative, most likely, optimistic). You should express costs in constant real dollar terms for the base year. You may also express the uncertainty of each cost estimate with a minimum and maximum percentage of the base value.

(g) A spending schedule. You should provide costs for each year (in real dollars) for each category in paragraphs (a) through (f) of this section.

(h) A summary of other costs which are ineligible for evaluating your need for relief. These costs cover:

(1) Expenses before first discovery on the field;

(2) Cash bonuses;

(3) Fees for royalty relief applications;

(4) Lease rentals, royalties, and payments of net profit share and net revenue share;

(5) Legal expenses;

(6) Damages and losses;

(7) Taxes;

(8) Interest or finance charges, including those embedded in equipment leases;

(9) Fines or penalties; and

(10) Money spent on previously existing obligations (e.g., royalty overrides or other forms of payment for acquiring a financial position in a lease, expenditures for plugging wells and removing and abandoning facilities that existed on the application submission date).

$203.90 What is in a fabricator's confirmation report?

This report shows you have committed in a timely way to the approved system for production. This report must include the following (or its equivalent for unconventionally acquired systems):

(a) A copy of the contract(s) under which the fabrication yard is building the approved system for you;

(b) A letter from the contractor building the system to the MMS's GOM Regional Supervisor-Production and Development, certifying when struction started on your system; and

con

(c) Evidence of an appropriate down payment or equal action that you've started acquiring the approved system.

§ 203.91 What is in a post-production development report?

For each cost category in the deep water cost report, you must compare actual costs up to the date when production starts to your planned pre-production costs. If your application included more than one development scenario, you need to compare actual costs with those in your scenario of most likely development. Keep supporting records for these costs and make them available to us on request.

Subpart C-Federal and Indian Oil [Reserved]

Subpart D-Federal and Indian Gas [Reserved]

Subpart E-Solid Minerals, General [Reserved]

Subpart F-Coal

§ 203.250 Advance royalty.

Provisions for the payment of advance royalty in lieu of continued operation are contained at 43 CFR 3483.4.

[54 FR 1522, Jan. 13, 1989]

§ 203.251 Reduction in royalty rate or rental.

An application for reduction in coal royalty rate or rental shall be filed and processed in accordance with 43 CFR group 3400.

[54 FR 1522, Jan. 13, 1989]

Subpart G-Other Solid Minerals [Reserved]

Subpart H-Geothermal
Resources [Reserved]

Subpart 1-OCS Sulfur [Reserved]
PART 206-PRODUCT VALUATION

Subpart A-General Provisions

Sec.
206.10 Information collection.
Subpart B-Indian Oil

206.50 Purpose and scope.

206.106 What

are my responsibilities to place production into marketable condition and to market production? 206.107 How do I request a value determination?

206.108 Does MMS protect information I provide?

206.109 When may I take a transportation allowance in determining value? 206.110 How do I determine a transportation allowance under an arm's-length transportation contract?

206.111 How do I determine a transportation allowance under a non-arm's-length transportation arrangement?

206.112 What adjustments and transportation allowances apply when I value oil using index pricing?

206.113 How will MMS identify market centers?

206.114 What are my reporting requirements under an arm's-length transportation contract?

206.115 What are my reporting requirements under a non-arm's-length transportation arrangement?

206.116 What interest and assessments apply if I improperly report a transportation allowance?

206.117 What reporting adjustments must I make for transportation allowances? 206.118 Are actual or theoretical losses permitted as part of a transportation allowance?

206.119 How are the royalty quantity and quality determined?

206.120 How are operating allowances determined?

206.252 Information collection. 206.253 Coal subject to royalties general provisions.

206.254 Quality and quantity measurement standards for reporting and paying royalties.

206.255 Point of royalty determination. 206.256 Valuation standards for cents-perton leases.

206.257 Valuation standards for ad valorem

leases.

206.258 Washing allowances-general.

206.259 Determination of washing allow

ances.

206.260 Allocation of washed coal.

Subpart A-General Provisions

$206.10 Information collection.

The information collection requirements contained in this part have been approved by the Office of Management and Budget (OMB) under 44 U.S.C. 3501 et seq. The forms, filing date, and approved OMB clearance numbers are identified in 30 CFR 210.10.

[57 FR 41863, Sept. 14, 1992]

Subpart B-Indian Oil

SOURCE: 61 FR 5455, Feb. 12, 1996, unless otherwise noted.

$206.50 Purpose and scope.

(a) This subpart is applicable to all oil production from Indian (Tribal and allotted) oil and gas leases (except leases on the Osage Indian Reservation, Osage County, Oklahoma). The purpose of this subpart is to establish the value of production, for royalty purposes, consistent with the mineral leasing laws, other applicable laws, and lease terms.

(b) If the specific provisions of any Federal statute, treaty, settlement agreement between the Indian lessor and a lessee resulting from administrative or judicial litigation, or oil and gas lease subject to the requirements of this subpart are inconsistent with any regulation in this subpart, then the statute, treaty, lease provision or settlement agreement shall govern to the extent of that inconsistency.

(c) All royalty payments made to MMS or Indian Tribes are subject to audit and adjustment.

(d) The regulations in this subpart are intended to ensure that the trust responsibilities of the United States with respect to the administration of Indian oil and gas leases are discharged in accordance with the requirements of the governing mineral leasing laws, treaties, and lease terms.

§ 206.51 Definitions.

For the purposes of this subpart:

Allowance means an approved or an MMS-initially accepted deduction in determining value for royalty purposes. Transportation allowance means an allowance for the reasonable, actual