Difference between revisions of "Cash flow model"

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==Data requirements==
 
==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:
+
 
 +
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 section]]s, 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:
 
# All front end costs—leases, geology and geophysics (G & G), overhead, exploration drilling, and completion costs
 
# All front end costs—leases, geology and geophysics (G & G), overhead, exploration drilling, and completion costs
−
# Projected dry hole costs
+
# Projected [[dry hole]] costs
 
# Ultimate recoverable reserves (including secondary recovery)
 
# Ultimate recoverable reserves (including secondary recovery)
 
# Field area (and thus number of producing wells), unless it's a single-well project
 
# Field area (and thus number of producing wells), unless it's a single-well project
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# Abandonment costs
 
# Abandonment costs
 
# 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 [[About taxes|tax rules]] for that country.  
 
# 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 [[About taxes|tax rules]] for that country.  
−
# Anticipated price or cost escalation schedule, if any (the example shown in 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.
+
# Anticipated price or cost escalation schedule, if any (the example shown in [[:Image:Charles-l-vavra-john-g-kaldi-robert-m-sneider capillary-pressure 1.jpg|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.
 
# Net revenue interest (NRI) of lease (1.00 - royalty interest) and company share of working interest
 
# Net revenue interest (NRI) of lease (1.00 - royalty interest) and company share of working interest
 
# Company discount rate
 
# Company discount rate
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==Calculations in the cash flow model==
 
==Calculations in the cash flow model==
−
 
−
[[File:Charles-l-vavra-john-g-kaldi-robert-m-sneider capillary-pressure 1.jpg|thumbnail|left|'''Table 1.''' Cash flow model for a development well]]
 
−
 
−
[[File:Rose time-value-of-money 1.jpg|thumbnail|left|'''Table 2.''' Comparison of project cash flows and equivalent present value fir example development well (in $ thousands)]]
 
  
 
The ''net cash flow'' (NCF) for each assumed time period, including time 0, can be determined using the following equation.
 
The ''net cash flow'' (NCF) for each assumed time period, including time 0, can be determined using the following equation.
  
−
:<math>\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} \ </math>
+
:<math>\text{After-tax NCF } = (\text{Net revenue interest}~ \times ~\text{Production} ~\times ~\text{Wellhead price})</math>
 +
::<math>-~\text{Wellhead taxes}~ - ~\text{Operating costs}~ - ~\text{Federal income taxes}~ - ~\text{Investments} \ </math>
  
 
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:
 
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:
  
−
:<math>\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} \ </math>
+
:<math>\text{After-tax NOI} = (\text{Net revenue interest}~\times~\text{Production}~\times~\text{Wellhead price})</math>
 +
::<math>-~\text{Wellhead taxes}~-~\text{Operating costs}~-~\text{Federal income taxes} \ </math>
 +
 
 +
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 [[The time value of money|cash flow time diagram]] can be prepared and we are ready to calculate the net present value for our venture.
  
−
[[File:Test.png|thumbnail|'''Table 3.''' Cash flow model for example multiwell extension project.]]
+
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.  
  
−
[[File:Charles-l-vavra-john-g-kaldi-robert-m-sneider capillary-pressure 3.jpg|thumbnail|'''Table 4.''' Assumptions for example multi well extension project]]
+
{| class="wikitable"
 +
|+ '''Table 1. Cash Flow Model for a Development Well.'''
 +
|-
 +
! colspan=10 | Cash Flow Worksheet
 +
|-
 +
| align=middle | Year || 0 || 1991 || 1992 || 1993 || 1994 || 1995 || 1996 || 1997 || 1998
 +
|-
 +
| colspan=10 align=middle | 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
 +
|-
 +
| colspan=10 align=middle | 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'''
 +
|}
 +
:<sup>Source: After Thompson and Wright (1992)</sup><br>
 +
:<sup>Assumed facts:</sup><br>
 +
::<sup>Independent Producer and Royalty Owner status, therefore eligible for percentage depletion</sup><br>
 +
::<sup>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</sup><br>
 +
::<sup>Assumed Time 0 investments made on 1-1-91:</sup><br>
 +
:::<sup>Lease Bonus and G&G (depletable basis for tax calculation) = $125,000</sup><br>
 +
:::<sup>IDC's (100 % expensed for tax calculation) = $950,000</sup><br>
 +
:::<sup>Tangible expenditures (depreciable basis for tax calculation) = $300,000</sup><br>
 +
::<sup>Estimated [[dry hole]] cost if the well is unsuccessful is $750,000 (After-tax = $750,000 x (1 - 0.34) = $495,000)
  
−
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 an example and explanation of a cash flow time diagram, see the previous chapter on [[The time value of money|The Time Value of Money]].)
+
A completed cash flow time diagram is shown in Table 2 along with the equivalent net present value calculation.
 +
{| class="wikitable"
 +
|+ 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
 +
|-
 +
| colspan=3 | Project NPV || $1015.6
 +
|}
  
−
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 [[:Image:http://wiki.aapg.org/File:Charles-l-vavra-john-g-kaldi-robert-m-sneider_capillary-pressure_1.jpg|Table 1]]. A completed cash flow time diagram is shown in [[:Image:Rose_time-value-of-money_1.jpg|Table 2]] along with the equivalent net present value calculation.
+
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.
  
−
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 [[:Image:Test.png|Table 3]]. Since the project has a longer life than the example development well, the results are summarized in a slightly different format. [[:Image:Charles-l-vavra-john-g-kaldi-robert-m-sneider_capillary-pressure_3.jpg|Table 4]] presents the production, investment, and tax assumptions for the multiwell extension project.
+
{| class="wikitable"
 +
|+ 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 ($M) 
 +
|-
 +
| 1991 || 96.066 || 48.033 || 500 || 84.057 || 42.029 || 18.00 || 1.50 || 1513.032 || 63.043 || 1576.075
 +
|-
 +
| 1992 || 148.787 || 74.394 || 500 || 130.189 || 65.094 || 18.00 || 1.50 || 2343.402 || 97.642 || 2441.043
 +
|-
 +
| 1993 || 177.72 || 88.861 || 500 || 155.507 || 77.753 || 18.00 || 1.50 || 2799.118 || 116.630 || 2915.748
 +
|-
 +
| 1994 || 193.601 || 96.801 || 500 || 169.401 || 84.701 || 18.00 || 1.50 || 3049.221 || 127.051 || 3176.271
 +
|-
 +
| 1995 || 106.251 || 53.125 || 500 || 92.969 || 46.485 || 18.00 || 1.50 || 1673.448 || 69.727 || 1743.175
 +
|-
 +
| 1996 || 58.312 || 29.156 || 500 || 51.023 || 25.511 || 18.00 || 1.50 || 918.408 || 38.267 || 956.675
 +
|-
 +
| 1997 || 32.002 || 16.001 || 500 || 28.002 || 14.001 || 18.00 || 1.50 || 504.033 || 21.001 || 525.034
 +
|-
 +
| 1998 || 16.290 || 8.145 || 500 || 14.254 || 7.127 || 18.00 || 1.50 || 256.572 || 10.690 || 267.262
 +
|-
 +
| 1999 || 7.575 || 3.788 || 500 || 6.628 || 3.314 || 18.00 || 1.50 || 119.313 || 4.971 || 124.284
 +
|-
 +
| 2000 || 2.793 || 1.396 || 500 || 2.444 || 1.222 || 18.00 || 1.50 || 43.983 || 1.833 || 45.816
 +
|-
 +
| 2001 || 0.168 || 0.084 || 500 || 0.147 || 0.073 || 18.00 || 1.50 || 2.642 || 0.110 || 2.752
 +
|-
 +
| '''Totals''' || '''839.566''' || '''419.783''' || '''500''' || '''734.621''' || '''367.10''' || || || || ||
 +
|}
 +
{| class="wikitable"
 +
! rowspan=2 | Year || colspan = 11 | XYZ Oil Company
 +
|-
 +
! Operating Costs ($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'''
 +
|}
 +
<sup>'''Assumptions for Example Multiwell Extension Project'''</sup><br>
 +
:<sup>NRI = 0.875</sup><br>
 +
:<sup>Wellhead tax on oil and gas revenue is 8%</sup><br>
 +
:<sup>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.</sup><br>
 +
:<sup>Incremental tax rate is 34%</sup><br>
 +
:<sup>Oil price is $18.00/bbl. Gas price is $1.50/MCF</sup><br>
 +
:<sup>Cost of Failure is assumed to be the after tax cost of 2 [[dry hole]]s.</sup><br>
 +
::<sup>(750,000 x (1 - 0.34) x 2 = $990,000)</sup><br>
 +
:<sup>Assumed investment schedule:</sup><br>
 +
::<sup>Time 0 investments made on 1-1-91:</sup><br>
 +
:::<sup>Lease bonus and G&G = $125,000</sup><br>
 +
:::<sup>IDC's (100% expensed for tax calculation) = $950,000 (for one completion)</sup><br>
 +
:::<sup>Tangible expenditures (depreciable basis for tax calculation) = $300,000</sup><br>
 +
::<sup>Other investments made during 1991:</sup><br>
 +
:::<sup>Lease bonus and G&G = $200,000</sup><br>
 +
:::<sup>IDC's (100% expensed for tax calculation) = $950,000 (for one completion)</sup><br>
 +
:::<sup>DHC's (100% expensed for tax calculation) = $1,500,000 (for two dry  holes)</sup><br>
 +
:::<sup>Tangible expenditures (depreciable basis for tax calculation) = $600,000</sup><br>
 +
::<sup>Investments made during 1992:</sup><br>
 +
:::<sup>Lease bonus and G&G = $100,000</sup><br>
 +
:::<sup>IDC's (100% expensed for tax calculation) = $950,000 (for one completion)</sup><br>
 +
:::<sup>Tangible expenditures (depreciable basis for tax calculation) = $300,000</sup><br>
 +
::<sup>Investments made during 1993:</sup><br>
 +
:::<sup>IDC's (100% expensed for tax calculation) = $950,000 (for one completion)</sup><br>
 +
:::<sup>Tangible expenditures (depreciable basis for tax calculation) = $300,000</sup><br>
 +
:<sup>Assumed Production Schedule</sup><br>
 +
::<sup>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.</sup><br>
 +
{{clear}}
  
 
==Points to remember==
 
==Points to remember==
 
Here are a few final points that are important to remember concerning cash flow models:
 
Here are a few final points that are important to remember concerning cash flow models:
−
# 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.  
+
# 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.  
 
# Do not carry out cash flow analysis of "risked reserves"—the cash flow model is built on the success case
 
# Do not carry out cash flow analysis of "risked reserves"—the cash flow model is built on the success case
 
# Net cash flow is the sum of outlays and inflows.
 
# Net cash flow is the sum of outlays and inflows.
Line 65: Line 225:
 
# 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.
 
# 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.
 
# 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.
 
# 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.
−
# Some firms use mid-year discounting (rather than end-of-year discounting) as being more realistic<ref name=Megill_1988>Megill, R. E., 1988, An introduction to exploration economics, 3rd ed.: Tulsa, OK, PennWell Books, 238 p.</ref>. Some firms use continuous rather than annual discounting.
+
# Some firms use mid-year discounting (rather than end-of-year discounting) as being more realistic.<ref name=Megill_1988>Megill, R. E., 1988, An introduction to exploration economics, 3rd ed.: Tulsa, OK, PennWell Books, 238 p.</ref> Some firms use continuous rather than annual discounting.
 
# 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.
 
# 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.
−
# The present value of most projects will decrease as successively higher corporate discount rates are utilized. The exception would be an acceleration project<ref name=Thompson_etal_1985>Thompson, R. S., and J. D. Wright, 1985, Oil property evaluation, 2nd ed.: Golden, CO, Thompson-Wright Associates, 212 p.</ref>. The discount rate at which the present value is zero is called the ''discounted cash flow rate of return'' ([[Key economic parameters|DCFROR]]).
+
# The present value of most projects will decrease as successively higher corporate discount rates are utilized. The exception would be an acceleration project<ref name=Thompson_etal_1985>Thompson, R. S., and J. D. Wright, 1985, Oil property evaluation, 2nd ed.: Golden, CO, Thompson-Wright Associates, 212 p.</ref>. The discount rate at which the present value is zero is called the ''[[Key economic parameters#Discounted cash flow rate of return|discounted cash flow rate of return]].''
 
# 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
 
# 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
 
# 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.")
 
# 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.")
Line 74: Line 234:
  
 
==See also==
 
==See also==
−
* [[Expected value and chance of success]]
+
* [[Risk: expected value and chance of success]]
−
* [[The time value of money]]
+
* [[Economics: time value of money]]
−
* [[Dealing with risk aversion]]
+
* [[Risk: dealing with risk aversion]]
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* [[Economics: fundamental equations for oil and gas property evaluation]]
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* [[Key economic parameters]]
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* [[Economics: key parameters]]
 
* [[Economics of property acquisitions]]
 
* [[Economics of property acquisitions]]
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* [[About taxes]]
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* [[Introduction to economics and risk assessment]]
 
* [[Introduction to economics and risk assessment]]
 
* [[Uncertainties impacting reserves, revenue, and costs]]
 
* [[Uncertainties impacting reserves, revenue, and costs]]
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[[Category:Methods in Exploration 10]]

Latest revision as of 19:27, 19 January 2022

Development Geology Reference Manual
Series Methods in Exploration
Part Economics and risk assessment
Chapter Building a cash flow model
Author Robert S. Thompson
Link Web page
PDF PDF file (requires access)

Intro should go here

Data requirements[edit]

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[edit]

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

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:

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[edit]

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.[1] 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[2]. 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[edit]

References[edit]

  1. ↑ Megill, R. E., 1988, An introduction to exploration economics, 3rd ed.: Tulsa, OK, PennWell Books, 238 p.
  2. ↑ Thompson, R. S., and J. D. Wright, 1985, Oil property evaluation, 2nd ed.: Golden, CO, Thompson-Wright Associates, 212 p.

External links[edit]

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