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30 C.F.R. §§ 203.83–203.91

9 sections in range

§203.83. What is in an administrative information report?

30 C.F.R. § 203.83

This report identifies the field or lease for which royalty relief is requested and must contain the following items:
(a)
The field or lease name;
(b)
The serial number of leases we have assigned to the field, names of the lease title holders of record, the lease operators, and whether any lease is part of a unit;
(c)
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);
(d)
The location of any new wells proposed under the terms of the application (not required for non-oil and gas leases);
(e)
A description of field or lease history;
(f)
Full information as to whether you will pay royalties or a share of production to anyone other than the United States, the amount you will pay, and how much you will reduce this payment if we grant relief;
(g)
The type of royalty relief you are requesting;
(h)
Confirmation that BOEM approved a DOCD or supplemental DOCD (Deep Water expansion project applications only); and
(i)
A narrative description of the development activities associated with the proposed capital investments and an explanation of proposed timing of the activities and the effect on production (Deep Water applications only).
Notes, amendments, and revision history

Authority

Authority: 25 U.S.C. 396 et seq.; 25 U.S.C. 396a et seq.; 25 U.S.C. 2101 et seq.; 30 U.S.C. 181 et seq.; 30 U.S.C. 351 et seq.; 30 U.S.C. 1001 et seq.; 30 U.S.C. 1701 et seq.; 31 U.S.C. 9701; 42 U.S.C. 15903-15906; 43 U.S.C. 1301 et seq.; 43 U.S.C. 1331 et seq.; and 43 U.S.C. 1801 et seq.

Source

Source: 76 FR 64462, Oct. 18, 2011, unless otherwise noted.

§203.84. What is in a net revenue and relief justification report?

30 C.F.R. § 203.84

This report presents cash flow data for 12 qualifying months, using the format specified in the “Guidelines for the Application, Review, Approval, and Administration of Royalty Relief for End-of-Life Leases”, U.S. Department of the Interior, BSEE. Qualifying months for an oil and gas lease are the most recent 12 months out of the last 15 months that you produced at least 100 BOE per day on average. Qualifying months for other than oil and gas leases are the most recent 12 of the last 15 months having some production.
(a)
The cash flow table you submit must include historical data for:
(1)
Lease production subject to royalty;
(2)
Total revenues;
(3)
Royalty payments out of production;
(4)
Total allowable costs; and
(5)
Transportation and processing costs.
(b)
Do not include in your cash flow table the non-allowable costs listed at 30 CFR 1220.013 or:
(1)
OCS rental payments on the lease(s) in the application;
(2)
Damages and losses;
(3)
Taxes;
(4)
Any costs associated with exploratory activities;
(5)
Civil or criminal fines or penalties;
(6)
Fees for your royalty relief application; and
(7)
Costs associated with existing obligations (e.g., royalty overrides or other forms of payment for acquiring the lease, depreciation on previously acquired equipment or facilities).
(c)
We may, in reviewing and evaluating your application, disallow costs when you have not shown they are necessary to operate the lease, or if they are inconsistent with end-of-life operations.
Notes, amendments, and revision history

Authority

Authority: 25 U.S.C. 396 et seq.; 25 U.S.C. 396a et seq.; 25 U.S.C. 2101 et seq.; 30 U.S.C. 181 et seq.; 30 U.S.C. 351 et seq.; 30 U.S.C. 1001 et seq.; 30 U.S.C. 1701 et seq.; 31 U.S.C. 9701; 42 U.S.C. 15903-15906; 43 U.S.C. 1301 et seq.; 43 U.S.C. 1331 et seq.; and 43 U.S.C. 1801 et seq.

Source

Source: 76 FR 64462, Oct. 18, 2011, unless otherwise noted.

§203.85. What is in an economic viability and relief justification report?

30 C.F.R. § 203.85

This report should show that your project appears economic without royalties and sunk costs using the RSVP model we provide. The format of the report and the assumptions and parameters we specify are found in the “Guidelines for the Application, Review, Approval and Administration of the Deep Water Royalty Relief Program,” U.S. Department of the Interior, BSEE. Clearly justify each parameter you set in every scenario you specify in the RSVP. You may provide supplemental information, including your own model and results. The economic viability and relief justification report must contain the following items for an oil and gas lease.
(a)
Economic assumptions we provide which include—
(1)
Starting oil and gas prices;
(2)
Real price growth;
(3)
Real cost growth or decline rate, if any;
(4)
Base year;
(5)
Range of discount rates; and
(6)
Tax rate (for use in determining after-tax sunk costs).
(b)
Analysis of projected cash flow (from the date of the application using annual totals and constant dollar values) which shows:
(1)
Oil and gas production;
(2)
Total revenues;
(3)
Capital expenditures;
(4)
Operating costs;
(5)
Transportation costs; and
(6)
Before-tax net cash flow without royalties, overrides, sunk costs, and ineligible costs.
(c)
Discounted values which include—
(1)
Discount rate used (selected from within the range we specify).
(2)
Before-tax net present value without royalties, overrides, sunk costs, and ineligible costs.
(d)
Demonstrations that—
(1)
All costs, gross production, and scheduling are consistent with the data in the G&G, engineering, production, and cost reports (§§ 203.86 through 203.89) and
(2)
The development and production scenarios provided in the various reports are consistent with each other and with the proposed development system. You can use up to three scenarios (conservative, most likely, and optimistic), but you must link each to a specific range on the distribution of resources from the RSVP Resource Module.
Notes, amendments, and revision history

Authority

Authority: 25 U.S.C. 396 et seq.; 25 U.S.C. 396a et seq.; 25 U.S.C. 2101 et seq.; 30 U.S.C. 181 et seq.; 30 U.S.C. 351 et seq.; 30 U.S.C. 1001 et seq.; 30 U.S.C. 1701 et seq.; 31 U.S.C. 9701; 42 U.S.C. 15903-15906; 43 U.S.C. 1301 et seq.; 43 U.S.C. 1331 et seq.; and 43 U.S.C. 1801 et seq.

Source

Source: 76 FR 64462, Oct. 18, 2011, unless otherwise noted.

§203.86. What is in a G&G report?

30 C.F.R. § 203.86

This report supports the reserve and resource estimates used in the economic evaluation and must contain each of the following elements.
(a)
Seismic data which includes—
(1)
Non-interpreted 2D/3D survey lines reflecting any available state-of-the-art processing technique in a format readable by BSEE and specified by the deep water royalty relief guidelines;
(2)
Interpreted 2D/3D seismic survey lines reflecting any available state-of-the-art processing technique identifying all known and prospective pay horizons, wells, and fault cuts;
(3)
Digital velocity surveys in the format of the GOA region's letter to lessees of 10/1/90;
(4)
Plat map of “shot points;” and
(5)
“Time slices” of potential horizons.
(b)
Well data which includes—
(1)
Hard copies of all well logs in which—
(i)
The 1-inch electric log shows pay zones and pay counts and lithologic and paleo correlation markers at least every 500-feet,
(ii)
The 1-inch type log shows missing sections from other logs where faulting occurs,
(iii)
The 5-inch electric log shows pay zones and pay counts and labeled points used in establishing resistivity of the formation, 100 percent water saturated (Ro) and the resistivity of the undisturbed formation (Rt), and
(iv)
The 5-inch porosity logs show pay zones and pay counts and labeled points used in establishing reservoir porosity or labeled points showing values used in calculating reservoir porosity such as bulk density or transit time;
(2)
Digital copies of all well logs spudded before December 1, 1995;
(3)
Core data, if available;
(4)
Well correlation sections;
(5)
Pressure data;
(6)
Production test results;
(7)
Pressure-volume-temperature analysis, if available; and
(8)
A table listing the wells and completions, and indicating which sands and fault blocks will be targeted for completion or recompletion.
(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)
An explanation for excluding the reservoirs you are not planning to develop.
(d)
Reservoir-specific data which includes—
(1)
Probability of reservoir occurrence with hydrocarbons;
(2)
Probability the hydrocarbon in the reservoir is all oil and the probability it is all gas;
(3)
Distributions or point estimates (accompanied by explanations of why distributions less appropriately reflect the uncertainty) for the parameters used to estimate reservoir size, i.e., acres and net thickness;
(4)
Most likely values for porosity, salt water saturation, volume factor for oil formation, and volume factor for gas formation;
(5)
Distributions or point estimates (accompanied by explanations of why distributions less appropriately reflect the uncertainty) for recovery efficiency (in percent) and oil or gas recovery (in stock-tank-barrels per acre-foot or in thousands of cubic feet per acre foot);
(6)
A gas/oil ratio distribution or point estimate (accompanied by explanations of why distributions less appropriately reflect the uncertainty) for each reservoir;
(7)
A yield distribution or point estimate (accompanied by explanations of why distributions less appropriately reflect the uncertainty) for each gas reservoir; and
(8)
Reserve or resource distribution by 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.
Notes, amendments, and revision history

Amendments

[76 FR 64462, Oct. 18, 2011, as amended at 90 FR 44326, Sept. 15, 2025]

Authority

Authority: 25 U.S.C. 396 et seq.; 25 U.S.C. 396a et seq.; 25 U.S.C. 2101 et seq.; 30 U.S.C. 181 et seq.; 30 U.S.C. 351 et seq.; 30 U.S.C. 1001 et seq.; 30 U.S.C. 1701 et seq.; 31 U.S.C. 9701; 42 U.S.C. 15903-15906; 43 U.S.C. 1301 et seq.; 43 U.S.C. 1331 et seq.; and 43 U.S.C. 1801 et seq.

Source

Source: 76 FR 64462, Oct. 18, 2011, unless otherwise noted.

Amendments

[76 FR 64462, Oct. 18, 2011, as amended at 90 FR 44326, Sept. 15, 2025]

§203.87. What is in an engineering report?

30 C.F.R. § 203.87

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 along with basic design specifications and drawings; 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 the conceptual basis for developing in phases and goals or milestones required for starting later phases.
(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.
Notes, amendments, and revision history

Authority

Authority: 25 U.S.C. 396 et seq.; 25 U.S.C. 396a et seq.; 25 U.S.C. 2101 et seq.; 30 U.S.C. 181 et seq.; 30 U.S.C. 351 et seq.; 30 U.S.C. 1001 et seq.; 30 U.S.C. 1701 et seq.; 31 U.S.C. 9701; 42 U.S.C. 15903-15906; 43 U.S.C. 1301 et seq.; 43 U.S.C. 1331 et seq.; and 43 U.S.C. 1801 et seq.

Source

Source: 76 FR 64462, Oct. 18, 2011, unless otherwise noted.

§203.88. What is in a production report?

30 C.F.R. § 203.88

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.
Notes, amendments, and revision history

Authority

Authority: 25 U.S.C. 396 et seq.; 25 U.S.C. 396a et seq.; 25 U.S.C. 2101 et seq.; 30 U.S.C. 181 et seq.; 30 U.S.C. 351 et seq.; 30 U.S.C. 1001 et seq.; 30 U.S.C. 1701 et seq.; 31 U.S.C. 9701; 42 U.S.C. 15903-15906; 43 U.S.C. 1301 et seq.; 43 U.S.C. 1331 et seq.; and 43 U.S.C. 1801 et seq.

Source

Source: 76 FR 64462, Oct. 18, 2011, unless otherwise noted.

§203.89. What is in a cost report?

30 C.F.R. § 203.89

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 costs. Report sunk costs in dollars not adjusted for inflation and only if you have documentation.
(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).
Notes, amendments, and revision history

Authority

Authority: 25 U.S.C. 396 et seq.; 25 U.S.C. 396a et seq.; 25 U.S.C. 2101 et seq.; 30 U.S.C. 181 et seq.; 30 U.S.C. 351 et seq.; 30 U.S.C. 1001 et seq.; 30 U.S.C. 1701 et seq.; 31 U.S.C. 9701; 42 U.S.C. 15903-15906; 43 U.S.C. 1301 et seq.; 43 U.S.C. 1331 et seq.; and 43 U.S.C. 1801 et seq.

Source

Source: 76 FR 64462, Oct. 18, 2011, unless otherwise noted.

§203.90. What is in a fabricator's confirmation report?

30 C.F.R. § 203.90

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 BSEE Regional Director for your region certifying when construction started on your system; and
(c)
Evidence of an appropriate down payment or equal action that you've started acquiring the approved system.
Notes, amendments, and revision history

Authority

Authority: 25 U.S.C. 396 et seq.; 25 U.S.C. 396a et seq.; 25 U.S.C. 2101 et seq.; 30 U.S.C. 181 et seq.; 30 U.S.C. 351 et seq.; 30 U.S.C. 1001 et seq.; 30 U.S.C. 1701 et seq.; 31 U.S.C. 9701; 42 U.S.C. 15903-15906; 43 U.S.C. 1301 et seq.; 43 U.S.C. 1331 et seq.; and 43 U.S.C. 1801 et seq.

Source

Source: 76 FR 64462, Oct. 18, 2011, unless otherwise noted.

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

30 C.F.R. § 203.91

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. Also, you must have this report certified by an independent CPA according to § 203.81(c).
Notes, amendments, and revision history

Authority

Authority: 25 U.S.C. 396 et seq.; 25 U.S.C. 396a et seq.; 25 U.S.C. 2101 et seq.; 30 U.S.C. 181 et seq.; 30 U.S.C. 351 et seq.; 30 U.S.C. 1001 et seq.; 30 U.S.C. 1701 et seq.; 31 U.S.C. 9701; 42 U.S.C. 15903-15906; 43 U.S.C. 1301 et seq.; 43 U.S.C. 1331 et seq.; and 43 U.S.C. 1801 et seq.

Source

Source: 76 FR 64462, Oct. 18, 2011, unless otherwise noted.