Cash flow model

Intro should go here

Data requirements

The basis of economic evaluation of any proposed drilling venture—a new field, pool, or just a single well—is the cash flow model of investments, expenses, taxes, and wellhead revenues involved with the project. The values for the parameters in this model must come from a geotechnical analysis (including maps, cross sections, and reservoir analysis) of the anticipated new field or well and from geotechnical estimates of area, ultimate recoverable reserves, and projected well production schedules. Here are the general data that are required:

1. All front end costs—leases, geology and geophysics (G & G), overhead, exploration drilling, and completion costs
2. Projected dry hole costs
3. Ultimate recoverable reserves (including secondary recovery)
4. Field area (and thus number of producing wells), unless it's a single-well project
5. Typical well production schedules, including initial production, decline rate, and producing life to abandonment
6. All development costs, classified for tax calculations as either tangible expenditures or intangible drilling and development costs (IDCs), and scheduled by the month and year
7. Annual operating cost per well
8. Wellhead prices, wellhead taxes, and transportation costs
9. Abandonment costs
10. Annual federal income taxes. The model can be adapted for the analysis of international prospects by changing this item in the cash flow model to "outsider's take." Simply apply the tax rules for that country.
11. Anticipated price or cost escalation schedule, if any (the example shown in Table 1 uses the constant dollar concept, thus no price or cost escalation schedule is provided). Inflation (loss of purchasing power) is also assumed to be zero.
12. Net revenue interest (NRI) of lease (1.00 - royalty interest) and company share of working interest
13. Company discount rate
14. Anticipated incremental income tax rate

The procedure is basically to plan out the life of the field, project, or well from the first expenditure through abandonment, assigning costs and revenues to events and dates.

Calculations in the cash flow model

The net cash flow (NCF) for each assumed time period, including time 0, can be determined using the following equation.

${\displaystyle {\text{After-tax$NCF }}=({\text{Net revenue interest}}~\times ~{\text{Production}}~\times ~{\text{Wellhead price}})}

$-~{\text{Wellhead taxes}}~-~{\text{Operating costs}}~-~{\text{Federal income taxes}}~-~{\text{Investments}}\$

Some of the economic parameters presented later utilize after-tax net operating income (NOI) as a measure of profit. After-tax NOI is defined as follows:

${\text{After-tax NOI}}=({\text{Net revenue interest}}~\times ~{\text{Production}}~\times ~{\text{Wellhead price}})$

$-~{\text{Wellhead taxes}}~-~{\text{Operating costs}}~-~{\text{Federal income taxes}}\$

After the revenue and expenditure schedule has been determined, we can now calculate cash income taxes for our project. Finally, once the cash income taxes have been calculated for each year, the cash flow time diagram can be prepared and we are ready to calculate the net present value for our venture.

For now, let's assume we are provided the cash income tax number, so we are ready to look at an example problem for a single development well. The assumptions for this example problem and a completed worksheet are presented in Table 1.

Table 1. Cash Flow Model for a Development Well.

Cash Flow Worksheet
Year	0	1991	1992	1993	1994	1995	1996	1997	1998
ASSUMED FACTS
Gross Oil Prod MBO	0.000	96.066	52.722	28.934	15.880	8.715	4.783	2.625	0.168
Gross Gas Prod MMCF	0.000	48.033	26.361	14.467	7.940	4.357	2.391	1.312	0.084
Working Interest	1.000	1.000	1.000	1.000	1.000	1.000	1.000	1.000	1.000
Net Revenue Interest	0.875	0.875	0.875	0.875	0.875	0.875	0.875	0.875	0.87
Oil Prices $/bbl	18.000	18.000	18.000	18.000	18.000	18.000	18.000	18.000	18.000
Gas Prices $/MCF	1.500	1.500	1.500	1.500	1.500	1.500	1.500	1.500	1.500
CALCULATIONS
Gross Income, $M	0.000	1576.075	864.968	474.705	260.503	142.978	78.468	43.064	2.752
—Operating Costs, $M	0.000	24.000	24.000	24.000	24.000	24.000	24.000	24.000	24.000
—Sev.Adv. Tax, $M	0.000	126.086	69.197	37.976	20.842	11.438	6.277	3.445	0.220
NOI BFIT, $M	0.000	1425.989	771.771	412.728	215.682	107.540	48.191	15.619	0.373
—Cash Taxes, $M	0.000	66.891	193.309	98.278	47.305	20.163	3.274	-3.798	-4.422
NOI AFIT, $M	0.000	1359.098	578.462	314.450	168.376	87.377	44.916	19.417	4.795
—Investment, $M	1375.000	0.000	0.000	0.000	0.000	0.000	0.000	0.000	0.000
NCF AFIT, $M	-1375.000	1359.098	578.462	314.450	168.376	87.377	44.916	19.417	4.795

^{Source: After Thompson and Wright (1992)}

^{Assumed facts:}

^{Independent Producer and Royalty Owner status, therefore eligible for percentage depletion}

^{NRI = 0.875, Wellhead tax on oil and gas revenue is 8%, annual operating cost is $24,000, incremental tax rate is 34%, oil price is $18/bbl, and gas price is $1.50/MCF}

^{Assumed Time 0 investments made on 1-1-91:}

^{Lease Bonus and G&G (depletable basis for tax calculation) = $125,000}

^{IDC's (100 % expensed for tax calculation) = $950,000}

^{Tangible expenditures (depreciable basis for tax calculation) = $300,000}

^{Estimated dry hole cost if the well is unsuccessful is $750,000 (After-tax = $750,000 x (1 - 0.34) = $495,000)}

A completed cash flow time diagram is shown in Table 2 along with the equivalent net present value calculation.

Table 2. Net Present Value Calculation

Time	Cash Flow	Discount Factor	Present Value
0	$-1375	1.0000	$-1375.0
1	1359.098	0.9615	1306.8
2	578.462	0.9246	534.8
3	314.450	0.8890	279.5
4	168.376	0.8548	143.9
5	87.377	0.8219	71.8
6	44.916	0.7903	35.5
7	19.417	0.7599	14.8
8	4.795	0.7307	3.5
Project NPV			$1015.6

The same steps also apply to a multiwell project. Field development projects are constructed by combining individual well models in a realistic time frame. The income tax calculation must be done on a total project basis since oil and gas taxation applies to the total property. An example of a multiwell field extension project is shown in Table 3. Since the project has a longer life than the example development well, the results are summarized in a slightly different format. The production, investment, and tax assumptions for the multiwell extension project are outlined below the table.

Table 3. Cash Flow Model for Example Multiwell Extension Project

Year	Gross Oil Production (Mbbl)	Gross Gas Production (MMSCF)	Gas-Oil Ratio (SF/STB)	XYZ Oil Co. Net Oil Production (Mbbl)	XYZ Oil Co. Net Gas Production (MMSCF)	Oil Price ($/bbl)	Gas Price ($MCF)	XYZ Oil Co. Oil Income ($M)	XYZ Oil Co. Gas Income ($M)	XYZ Oil Co. Gross Income ($M)
1991	96.066	48.033	500	84.057	42.029	18.00	1.50	1513.032	63.043	1576.075
1992	148.787	74.394	500	130.189	65.094	18.00	1.50	2343.402	97.642	2441.043
1993	177.72	88.861	500	155.507	77.753	18.00	1.50	2799.118	116.630	2915.748
1994	193.601	96.801	500	169.401	84.701	18.00	1.50	3049.221	127.051	3176.271
1995	106.251	53.125	500	92.969	46.485	18.00	1.50	1673.448	69.727	1743.175
1996	58.312	29.156	500	51.023	25.511	18.00	1.50	918.408	38.267	956.675
1997	32.002	16.001	500	28.002	14.001	18.00	1.50	504.033	21.001	525.034
1998	16.290	8.145	500	14.254	7.127	18.00	1.50	256.572	10.690	267.262
1999	7.575	3.788	500	6.628	3.314	18.00	1.50	119.313	4.971	124.284
2000	2.793	1.396	500	2.444	1.222	18.00	1.50	43.983	1.833	45.816
2001	0.168	0.084	500	0.147	0.073	18.00	1.50	2.642	0.110	2.752
Totals	839.566	419.783	500	734.621	367.10

Year	XYZ Oil Company
	Operating Costs ($M)	State + Local Tax ($M)	Net Oper. Inc BFIT ($M)	Total Cash Invest ($M)	Net Cash Flow BFIT ($M)	Fed. Inc. Tax ($M)	Net Cash Flow AFIT ($M)	Cum. NCF AFIT ($M)	Disc. NCF AFIT @ 4% ($M)	Cum. Disc. NCF AFIT @ 4% ($M)	Disc. Invest @ 4% ($M)
0				1375.000	-1375.000		-1375.000	-1375.000	-1375.000	-1375.000	1375.000
1991	24.000	126.086	1425.989	3250.000	-1824.011	-727.504	-1096.507	-2471.507	-1054.333	-2429.333	3125.000
1992	48.000	195.283	2197.760	1350.000	847.760	210.240	637.520	-1833.987	589.423	-1839.911	1248.151
1993	72.000	233.260	2610.488	1250.000	1360.488	322.798	1037.690	-796.297	922.503	-917.408	1111.245
1994	96.000	254.102	2826.170	0.000	2826.170	717.869	2108.301	1312.004	1802.184	884.776	0.000
1995	96.000	139.454	1507.721	0.000	1507.721	365.818	1141.903	2453.907	938.561	1823.337	0.000
1996	96.000	76.534	784.141	0.000	784.141	168.643	615.497	3069.404	486.437	2309.774	0.000
1997	96.000	42.003	387.031	0.000	387.031	59.271	327.760	3397.165	249.071	2558.845	0.000
1998	74.158	21.381	171.723	0.000	171.723	12.891	158.833	3555.997	116.057	2674.902	0.000
1999	50.158	9.943	64.183	0.000	64.183	1.826	62.357	3618.355	43.811	2718.714	0.000
2000	26.158	3.665	15.993	0.000	15.993	0.000	15.993	3634.347	10.804	2729.518	0.000
2001	2.158	0.220	0.374	0.000	0.374	0.000	0.374	3634.721	0.243	2729.760	0.000
Totals	680.632	1101.931	11991.572	7225.000	4766.572	1131.851	3634.721		2729.760		6859.396

^{Assumptions for Example Multiwell Extension Project}

^{NRI = 0.875}

^{Wellhead tax on oil and gas revenue is 8%}

^{Annual operating cost is $24,000/well. Note in the last four years the operating costs are not a multiple of $24,000. This is because the typical well produces only a fraction of a year in the eighth year.}

^{Incremental tax rate is 34%}

^{Oil price is $18.00/bbl. Gas price is $1.50/MCF}

^{Cost of Failure is assumed to be the after tax cost of 2 dry holes.}

^{(750,000 x (1 - 0.34) x 2 = $990,000)}

^{Assumed investment schedule:}

^{Time 0 investments made on 1-1-91:}

^{Lease bonus and G&G = $125,000}

^{IDC's (100% expensed for tax calculation) = $950,000 (for one completion)}

^{Tangible expenditures (depreciable basis for tax calculation) = $300,000}

^{Other investments made during 1991:}

^{Lease bonus and G&G = $200,000}

^{IDC's (100% expensed for tax calculation) = $950,000 (for one completion)}

^{DHC's (100% expensed for tax calculation) = $1,500,000 (for two dry holes)}

^{Tangible expenditures (depreciable basis for tax calculation) = $600,000}

^{Investments made during 1992:}

^{Lease bonus and G&G = $100,000}

^{IDC's (100% expensed for tax calculation) = $950,000 (for one completion)}

^{Tangible expenditures (depreciable basis for tax calculation) = $300,000}

^{Investments made during 1993:}

^{IDC's (100% expensed for tax calculation) = $950,000 (for one completion)}

^{Tangible expenditures (depreciable basis for tax calculation) = $300,000}

^{Assumed Production Schedule}

^{The production forecast for the typical well in the Example Development Well was used for the Multiwell Extension Project. A typical well was assumed to be placed on production at the beginning of each of the years 1991, 1992, 1993, and 1994.}

Points to remember

Here are a few final points that are important to remember concerning cash flow models:

1. Cash flow analysis is the third step in evaluating a proposed (or existing) petroleum property; it occurs after estimating (a) the reserves, rates, and costs and (b) the chance of success.
2. Do not carry out cash flow analysis of "risked reserves"—the cash flow model is built on the success case
3. Net cash flow is the sum of outlays and inflows.
4. Any investment is a purchase of anticipated future annual cash flows.
5. A permanent alternative to any petroleum venture is to put the investment capital "in the bank" (that is, alternative safe investments), where it will earn regular interest at the corporate rate.
6. If prices and costs are assumed to be in terms of constant purchasing power, then the discount component should only include the real interest component. The inflation component should not be included. If the prices and costs are escalated, then the discount rate selected should include the real interest rate and the inflation component.
7. Higher discount rates tend to favor shorter term and lower dollar volume projects (in preference to longer term and higher dollar volume projects), whereas lower discount rates allow substandard projects that may be a drag on corporate earnings. Either excess is deleterious, but the excessively high discount rate is clearly more harmful.
8. Some firms use mid-year discounting (rather than end-of-year discounting) as being more realistic. Some firms use continuous rather than annual discounting.
9. Although the final cumulative net present value can only be determined by projecting the cash flow model out through the full life of the field, the final few years will typically represent only a small fraction of its worth. Ordinarily, a field production model of about 15 years will be adequate for most purposes, except in the case of very large fields or in cases of "late" enhanced oil recovery (EOR) projects on older fields.
10. The present value of most projects will decrease as successively higher corporate discount rates are utilized. The exception would be an acceleration project. The discount rate at which the present value is zero is called the discounted cash flow rate of return.
11. All figures and estimates should be objective. You should neither purposefully overestimate (to sell the deal) nor underestimate (to be conservative and thereby protect yourself from being wrong). Be professional, give it your best shot
12. It is a good idea to make several cash flow "cases" using different assumptions for reserves, number of wells, initial potentials (IPs), and decline rates. This is easy to do using modern software. Such sensitivity analyses give the decision maker a better idea of the range of possibilities for project outcomes. However, one shortcoming of many sensitivity analyses is that no probability of occurrence can be assigned to a given case. As a result, the decision maker has an idea of the range of possible outcomes, but no sense of the chance of occurrence of any one outcome Fortunately, this deficiency is readily correctable by using probabilistic ranges for key variables and Monte Carlo simulation to combine such variables. (For more information on ranges and probabilities, see the chapter on "Uncertainties Impacting Reserves, Revenue, and Costs.")
13. A final step from such sensitivity analyses is the identification of critical threshold values necessary for the project to be commercial. In particular, requisite values for net pay, porosity, and initial production rate may be crucial in helping the well site geologist or engineer to make critical decisions on testing, stimulation, completion, or abandonment. These predetermined values should accompany the geologist or engineer to the well site.
14. There are many commercial computer programs available for both mainframe and microcomputer hardware that carry out cash flow modeling routinely and quickly, allowing many different values to be input for the significant parameters. Use of such software greatly simplifies the process of cash flow modeling once the procedure is fully understood. But for those who want to test their understanding, construct your model from scratch on a spreadsheet. It is not that hard and may prove to be an invaluable learning exercise.

See also

• Risk: expected value and chance of success
• Economics: time value of money
• Risk: dealing with risk aversion
• Economics: fundamental equations for oil and gas property evaluation
• Economics: key parameters
• Economics of property acquisitions
• Taxes
• Introduction to economics and risk assessment
• Uncertainties impacting reserves, revenue, and costs

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