1995 National Oil and Gas Assessment and Onshore Federal Lands
Donald L. Gautier, Gordon L. Dolton and Emil D. Attanasi

U. S. Geological Survey Open-File Report 95-75-N
January 1998

Appendix C.  Economic Assumptions for preparing incremental cost functions

General Assumptions:
1.  The economic analysis uses the mean of the assessed hydrocarbons.
2.  Industry exhibits rational behavior, so that investment will not be undertaken unless the full operating costs, investment costs, and the cost of capital can be recovered.
3.  Incremental costs include all the costs of finding, developing, and producing oil and gas in a particular geographic area.  For undiscovered conventional fields, exploration effort, ordering and arrival rate of discoveries, and finding costs are computed with province level finding rate functions (see Attanasi and others, 1996).  Data were insufficient for recalibrating undiscovered conventional field finding rate functions for only Federal Lands within each province (see footnote 3 in text for effect of including finding cost on economically recoverable oil and gas resources).  For continuous-type accumulations and coalbed gas accumulations, it was assumed that the industry could not selectively drill, therefore, industry would not initiate exploration of the play at a given depth interval unless the aggregate after-tax net present value of the commercially developable cells was sufficient to cover all costs of exploration associated with that 5,000 foot depth interval.
4. Industry was assumed to use a 12 percent after-tax rate of return as a hurdle rate or required rate of return to undertake new investment.  The cash flow analysis was specific to individual projects and ignored minimum income taxes and tax preference items that might be important from a corporate accounting stance. 
5.  Federal taxes are based on the 1986 Tax Reform Act and the 1993 revision.   State tax rates were as of 1993.  Costs levels are those that prevailed in 1993.
6.  Royalty payment to the resource owner is 12.5 percent of gross revenues for onshore areas and 16.67 percent for State offshore areas.
7.  Dry gas (gas without natural gas liquids) prices were assumed to be two-thirds the price of oil when expressed on an equivalent energy basis.  For example, if oil prices are $18 per barrel the implied price of gas would be $2 per mcf.  This relationship between oil and gas prices corresponds roughly to the historical average.   The analysis also focused on prices between $18 per barrel ($2 per mcf) and $30 per barrel ($3.34 per mcf).  Also, the well head price of natural gas liquids is assumed to be three-fourths the per barrel price of crude oil.
8.  By-product revenues from associated gas and natural gas liquids are credited in the economic evaluation to the primary products of either crude oil or non-associated natural gas in the calculation of the incremental cost functions.

Specific assumptions: Undiscovered conventional
1.  Economic evaluation of undiscovered conventional oil and gas fields was generally prepared at the province level and based on the assessed field-size distribution of undiscovered fields within 5,000 foot depth intervals.
2.  Exploration continues until the expected net present value of the commercially developable resources discovered by the last increment of wildcat drilling is insufficient to pay for that increment of wildcat drilling.
3.  Except in the Northern Alaska province (001), oil and gas prices used in the economic evaluation were well head prices.  For the Northern Alaska province, the oil price used in the economic evaluation was the Lower 48 West Coast price, rather than the well head price, so incremental costs include transportation from the field to the Lower 48 West Coast.  Oil produced in Northern Alaska is transported through the Trans-Alaska Pipeline System (TAPS).
4.  Because of the absence of a market for the gas resources of Northern Alaska, non-associated gas fields were not evaluated and a zero price was attached to the extracted associated gas from oil fields.
5.  The oil and gas resources of ?Central Alaska and Southern Alaska, provinces (002, 003), outside the Cook Inlet were not evaluated by the economic analysis because these areas have very limited potential and expected discovery sizes are insufficient to offset cost barriers imposed by the hostile climate, primitive infrastructure, and remoteness from markets.
6.  Technically recoverable resources assigned to Lake Michigan and Lake Erie were not evaluated in the economic analysis.  The technically recoverable resources amounts to 0.67 BBO and 3.0 TCFG.

Specific assumptions: Continuous-type and coalbed gas plays
1.  Economic evaluations of continuous-type accumulations and coalbed gas were prepared at the play level and based on the expected cell-size frequency distribution of untested cells for each 5,000 foot depth interval over which the play extends.
2.  Each untested cell requires a new well; recompletions to the target plays of producing wells were not considered.
3.  Within continuous-type or coalbed gas plays, it is assumed there is no trend in the discovery rate or well productivities as drilling progresses.  In particular, it is assumed that within a play, operators cannot high-grade areas except by restricting drilling to specific depth intervals.  To the extent possible, so-called sweet spots were made separate plays.

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