Taxes

Development Geology Reference Manual
Series	Methods in Exploration
Part	Economics and risk asseement
Chapter	About taxes
Author	Robert S. Thompson
Link	Web page
Store	AAPG Store

Oil and gas taxes are of two general types: wellhead or production taxes, which are paid when the oil and gas are produced regardless of the amount of profit (or loss), and income taxes, which are paid on the amount of profit (called taxable income) defined by the IRS. Wellhead taxes in most states average about 5 to 10% of the revenue, and the current corporate income tax rate varies from 15% to 39% (see Table 1). Wellhead taxes include excise, ad valorem, and severance taxes.

Table 1 Federal income tax schedules and rules

Taxable Income	Rate (%)
Not over cost::50,000 USD	15
Over cost::50,000 USD, less than cost::75,000 USD	25
Over cost::75,000 USD, less than cost::100,000 USD	34
Over cost::100,000 USD, less than cost::335,000 USD	39
Over cost::335,000 USD	34

In federal income taxation, the fundamental concept being applied is the tax free return of invested capital. Congress legislates the definition of profit and thus when the investor will receive the tax free return of his investment. Expenditures in which the tax payer receives immediate tax free return are called expensed, whereas expenditures in which the tax payer spreads the tax free return of his investment over several years are said to be capitalized. The timing of the tax deduction for the capitalized expenditures are determined by a set of rules for depreciation, depletion, and amortization.

Oil and gas taxation is one of the most difficult areas of taxation. We attempt here to provide only a foundation of knowledge by presenting basic oil and gas terminology as it applies to taxation and a detailed tax model.

Oil and gas taxation terminology

Several important terms are used in oil and gas taxation practices of which the reader should be aware.

Leasehold costs

Leasehold costs are expenditures associated with the acquisition of an economic interest in a natural resource that are deemed to benefit future tax periods. Accordingly, leasehold costs are capitalized, and the tax free return of that expenditure are recovered through the allowable depletion calculation. The depletion deduction was created by Congress to give a means of returning the invested capital to the investor tax free as the resource is depleted. There are two methods of calculating depletion: cost depletion and percentage depletion. (See “Determining owners of oil and gas interests" and "Methods of conveyance” for more information on lease ownership costs and revenue.)

Lease bonus

The payment made by the lessee to the lessor for the right to explore for oil and gas and develop the property is called a lease bonus. The lease bonus payment made by the lessee is capitalized by the lessee and recovered through the allowable depletion calculation. (See “Nature of the oil and gas lease” for more on leases.)

Geological and geophysical (G & G) costs

Geological and geophysical (G & G) costs are expenditures for geological studies and geophysical work such as seismic surveys. If the expenditures result in the acquisition and retention of a property, the expenditures are capitalized and the tax free return of the investment is determined from the allowable depletion calculation. If the G & G costs do not lead to the acquisition or retention of a property, then these costs can be expensed in the taxable year the property is relinquished.

Lease and well equipment

Lease and well equipment includes such items as the wellhead, flow lines, separators, and other equipment necessary to operate the property as well as the labor to install the equipment. Expenditures for tangible items such as these are capitalized, and the tax free return of the expenditure is recovered through depreciation calculations. Other examples of tangible items include surface and production casing, even though the casing is cemented in the well and has no apparent salvage value. Upon abandonment, any undepreciated amount would be written off. The depreciation rules are always changing. As a result of the 1986 Tax Reform Act, the depreciation system is called the Modified Accelerated Cost Recovery System (MARCS) (see Table 1).

Intangible drilling and development costs (IDCs)

Special tax treatment for expenditures classified as intangible drilling and development costs, or IDCs, is available to the tax payer. U.S. Treasury Regulation 1.612-4 states that “all expenditures made by an operator for wages, fuel, repairs, hauling,…, incident to and necessary for the drilling of wells and the preparation of the well for the production of oil and gas” are IDCs. A well is considered to be prepared for production when the wellhead is installed. Table 1 shows the current tax treatment of IDCs. Again, tangible items such as surface casing and production casing are classified as tangible expenditures, and the tax free return of the expenditure is recovered through depreciation.

Lease operating expenses

Lease operating expenses are expenditures incurred in the day-to-day activities of the production operations. Basically, costs incurred during the current tax period that were spent in an effort to generate revenues during the current tax period are treated as current period expenses. Direct labor, power costs, and maintenance costs are some examples.

Current tax treatment

The last significant overhaul of oil and gas taxation is the result of the 1986 Tax Reform Act. An analysis and comparison of the tax rules prior to and after the 1986 Tax Reform Act are presented by Thompson. Table 1 summarizes the current tax treatment for the integrated producer (typically, the major oil companies) and the independent producer and royalty owner (IPRO). The tax definitions for an IPRO and an integrated producer are presented in Ernst and Young's Oil and Gas Federal Income Taxation. As you can see from Table 1, the IPRO receives preferential tax treatment.

Calculating after-tax net cash flow

The recommended approach to calculate after-tax net cash flow (NCF) is to use Equation 1, which is

${\displaystyle {\mbox{After-tax$NCF}}=({\mbox{Net revenue interest}}\times {\mbox{Production}}\times {\mbox{Wellhead price}})-{\mbox{Wellhead taxes}}-{\mbox{Operating costs}}-{\mbox{Federal income taxes}}-{\mbox{Investments}}}

All transactions in the equation are cash items, one of which is cash income taxes. The separation of the tax calculation from the NCF calculation is recommended because of the many complications in oil and gas taxation. Instead of combining the NCF calculation and the tax calculation, the federal income tax model for oil and gas transactions (Figure 1) should be used to calculate the yearly taxes for the property, taking into consideration the appropriate tax treatment of each of the transactions. Once a cash tax liability (negative tax = tax savings) is calculated, this tax amount is subtracted, as shown in Equation 1.

It sounds simple and it actually is, once some experience is gained. Two worksheets are provided to help keep the numbers straight. Tables 2 and 3 are the completed worksheets for the example development well in which the producer is an independent producer and royalty owner eligible for percentage depletion. Table 4 is the federal income tax calculations for the example multiwell extension project.

Table 2 Income tax calculations for example development well. All amounts $M.

Year	1991	1992	1993	1994	1995	1996	1997	1998
Gross Inc. (Gl)	1576.075	864.968	474.705	260.523	142.978	78.468	43.064	2.752
– Operating Costs	24.000	24.000	24.000	24.000	24.000	24.000	24.000	2.158
– Sev.Adv.Tax	126.086	69.197	37.976	20.842	11.438	6.277	3.445	0.220
– IDC Expense	950.000	0.000	0.000	0.000	0.000	0.000	0.000	0.000
– IDC Amortization	0.000	0.000	0.000	0.000	0.000	0.000	0.000	0.000
– Depreciation	42.840	73.470	52.470	37.470	26.790	26.790	26.790	13.380
Taxable Income Before Depletion	433.149	698.301	360.258	178.212	80.750	21.401	–11.171	–13.007
– Depl. Allowance	236.411	129.745	71.206	39.079	21.447	11.770	0.000	0.000
Taxable Income	196.738	568.556	289.053	139.133	59.303	9.630	–11.171	–13.007
Cash Tax Before Credits and Minimum Tax	66.891	193.309	98.278	47.305	20.163	3.274	–3.798	–4.422
– Tax Credit
+ Minimum Tax
Final Cash Tax	66.891	193.309	98.278	47.305	20.163	3.274	–3.798	–4.422

Table 3 Depreciation, depletion, and amortization calculations for example development well

Year	1991	1992	1993	1994	1995	1996	1997	1998
AMORTIZATION
Capitalized IDCs, $M	0.000
Amortization rate	0.20	0.20	0.20	0.20	0.20
IDC Amortization, $M	0.000	0.000	0.000	0.000	0.000
DEPRECIATION
Depr. basis (tangibles), $M	300.000
7-year MACRS rates	0.1428	0.2449	0.1749	0.1249	0.0893	0.0893	0.0893	0.044
Depreciation Expense, $M	42.840	73.470	52.470	37.470	26.790	26.790	26.790	13.380
DEPLETION
Depletion basis, $M	125.000	0.000	0.000	0.000	0.000	0.000	0.000	0.000
Cost depletion, $M	57.211	0.000	0.000	0.000	0.000	0.000	0.000	0.000
15 % Gl	236.411	129.745	71.206	39.079	21.447	11.770	6.460	0.413
100 % TIBD	433.149	698.301	360.258	178.212	80.750	21.401	–11.171	–13.007
Percentage depletion, $M
Lessor of 15% Gl or 100%
TIBD	236.411	129.745	71.206	39.079	21.447	11.770	–11.171	–13.007
Allowable Depletion, $M
Greater Cost or %	236.411	129.745	71.206	39.079	21.447	11.770	0.000	0.000
Gross oil production (MBO)	96.066	52.722	28.934	15.880	8.715	4.783	2.625	0.168
Oil res. beg. of period	209.892	113.826	61.104	32.170	16.290	7.575	2.793	0.168

Table 4 Federal income tax calculations for example multiwell extension project

Year	Gross Income ($M)	Operat. Costs ($M)	SEV&ADV Tax ($M)	IDCs DHCs ($M)	DEPR	TIBD ($M)	Cost Depletion ($M)	Percent Depletion ($M)	Allowable Depletion ($M)	Taxable Income ($M)	Tax Credits ($M)	Cash Taxes ($M)
1991	1576.075	24.000	126.086	3400.000	128.520	–2102.531	37.187	–2102.531	37.187	–2139.718	0.000	–727.504
1992	2441.043	48.000	195.283	950.000	263.250	984.510	77.608	366.156	366.156	618.353	0.000	210.240
1993	2915.748	72.000	233.260	950.000	273.720	1386.768	6.472	437.362	437.362	949.406	0.000	322.798
1994	3176.271	96.000	254.102	0.000	238.350	2587.820	0.000	476.441	476.441	2111.379	0.000	717.869
1995	1743.175	96.000	139.454	0.000	170.310	1337.411	0.000	261.476	261.476	1075.935	0.000	365.818
1996	956.675	96.000	76.534	0.000	144.630	639.511	0.000	143.501	143.501	496.009	0.000	168.643
1997	525.034	96.000	42.003	0.000	133.950	253.081	0.000	78.755	78.755	174.326	0.000	59.271
1998	267.262	74.158	21.381	0.000	93.720	78.003	0.000	40.089	40.089	37.914	0.000	12.891
1999	124.284	50.158	9.943	0.000	40.170	24.013	0.000	18.643	18.643	5.371	0.000	1.826
2000	45.816	26.158	3.665	0.000	13.380	2.613	0.000	2.613	2.613	0.000	0.000	0.000
2001	2.752	2.158	0.220	0000	0.000	0.374	0.000	0.374	0.374	0.000	0.000	0.000
				5300.000	1500.000				1862.597			1131.851

The case for an integrated producer is an easier case since the producer can only take cost depletion.

Figure 2 Depletion allowance calculation. Note that remaining reserves (U) are end of year. In cost depletion calculation, S = sales during year. (After .)

Calculating allowable depletion

Determining the allowable depletion deduction is probably the most difficult calculation. Figure 2 is intended to help with this calculation. As shown in Figure 2, allowable depletion is the greater of cost depletion or percentage depletion. Cost depletion is calculated by taking the remaining depletable basis (unrecovered G & G costs and lease bonus) and multiplying by the fraction of the remaining reserves produced during the year (production during the year divided by reserves at the beginning of the year). All producers are eligible for cost depletion. Independent producers and royalty owners are also eligible for percentage depletion. Percentage depletion is the lesser of 15% of gross income or 100% of taxable income before depletion from the property. Prior to January 1, 1991, the Taxable Income limitation was 50% for each property. This change is the result of the Revenue Reconciliation Act of 1990. This recent change also demonstrates the “dynamics” of tax rules and the importance of seeking professional advice in this area. An example of another complication in the tax law is the 65% of taxable income limitation from all sources (not just limited to the producing property). The 65% taxable income limit from all sources is difficult to apply to single project economics and is ignored in the example problems presented.

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