Vose SoftwareModelRisk example · Oil and gas
Exploration Prospect Economics
Should we drill the exploration well? Expected monetary value of an oil prospect — from geological chance to discounted cash flow.
From the model’s saved run
The drilling decision
Expected monetary value (EMV) = the average value of drilling over all simulated wells, dry holes included.
| Measure | Unit | Value |
|---|---|---|
| Expected monetary value of drilling, EMV | US$m | 40.4 |
| Recommendation | Drill: positive expected value | |
| Chance of a commercial discovery | probability | 26.3% |
| Chance the well loses money (Prospect NPV < 0) | probability | 79.8% |
| Exploration well cost (mean, spent whatever the result) | US$m | 39.5 |
| Prospect NPV, P90 (low) | US$m | −46.0 |
| Prospect NPV, P10 (high) | US$m | 253.9 |
| Geological chance of success, Pg (input, for comparison) | probability | 29.4% |
S-curve (cumulative probability) of Prospect NPV (risked), Development NPV (success case) from the saved simulation.
The business question
An exploration well on the Kestrel prospect will cost around US$40 million. The exploration team puts the chance of finding oil at about 30%, and if oil is found its volume is highly uncertain. A discovery is developed only if it is larger than the minimum economic field size.
Its value then depends on how much oil can be produced, how soon, at what cost and at what oil price. The model combines all of these uncertainties to answer three questions: (1) is the expected monetary value of drilling positive? (2) what are the chances of a dry hole, a discovery too small to develop and a commercial discovery?
(3) which uncertainties drive the value of a discovery, and so where should appraisal focus?
- Who it is for
- Exploration teams, petroleum economists, portfolio managers and investment committees.
- Main outputs
- EMV of drilling · chance of a dry hole, a sub-commercial and a commercial discovery · success-case volumes and NPV · ranking of value drivers.
How the model works
Four sheets after this one, read from left to right. Each one feeds the next.
Inputs sheet
Every assumption in one place. Expert ranges are entered as PERT (minimum, most likely, maximum) or Lognormal (P90, P10) distributions. Porosity and water saturation are correlated with a Normal copula.
Prospect sheet
The geological chance of success, Pg, is the product of four independent risk factors, and a Bernoulli trial decides whether this simulated well finds oil. The volumetric equation gives the recoverable volume. A discovery is commercial if it reaches the minimum economic field size. The wells, facilities and capex are sized from its plateau rate, and a risk event adds a possible major cost overrun.
Cash flow sheet
An annual model of the success case: plateau-then-decline production, one random path of a mean-reverting oil price (VoseTimeGBMVR), royalty, operating and abandonment costs, and tax with immediate expensing and loss carry-forward. Production stops at the economic limit. The risked cash flow then applies the outcome of the well: exploration is always paid for, appraisal only after a discovery, development only after a commercial discovery.
Results sheet
The mean of the risked Prospect NPV over all samples is the EMV. VoseSim… functions bring the simulation statistics back into the workbook: outcome probabilities, P90 / P50 / P10 ranges, value drivers and charts.
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The results in detail
Outcomes of drilling the well
Simulated share of wells ending in each outcome.
Probability of at least each value of Chance of at least this volume, P90 / P50 / P10 from the saved simulation.
| Outcome | Probability |
|---|---|
| Dry hole | 70.5% |
| Oil found, but too small to develop | 3.2% |
| Commercial discovery | 26.3% |
| Total | 100.0% |
What a discovery would be worth (success case)
Before the chance of success is applied. P90 = low case (90% chance of being exceeded), P10 = high case.
| Measure | Unit | P90 (low) | P50 | P10 (high) | Mean |
|---|---|---|---|---|---|
| Recoverable volume | MMbbl | 19.1 | 41.5 | 89.2 | 49.6 |
| Plateau production | kbbl/d | 5.3 | 11.6 | 25.1 | 13.8 |
| Development capex | US$m | 365.8 | 608.4 | 1,120.9 | 695.1 |
| Development NPV if developed | US$m | −54.8 | 183.9 | 745.1 | 287.9 |
| Average realised oil price | US$/bbl | 57.3 | 74.4 | 97.3 | 76.2 |
| Field life | years | 13.0 | 16.0 | 20.0 | 16.4 |
| Chance a discovery is too small to develop | probability | 11.3% | |||
| Chance a development would lose money (NPV < 0) | probability | 18.7% |
What drives the value of a discovery
Lowest and highest mean development NPV over ten equal groups of each input (VoseSimSensitivityMean), drawn from the overall mean.
Tornado chart: the inputs ranked by how far the mean output moves across each input’s range.
The ranking as a table 12 inputs
| Input (ranked by influence) | Lowest mean | Highest mean | Rank |
|---|---|---|---|
| Productive area | 35.1 | 746.8 | 1 |
| Net pay | 66.0 | 635.3 | 2 |
| Long-term oil price | 156.8 | 459.6 | 3 |
| Recovery factor | 176.0 | 395.7 | 4 |
| Porosity | 185.7 | 375.1 | 5 |
| Water saturation | 202.3 | 362.1 | 6 |
| Major cost overrun | 160.5 | 317.6 | 7 |
| Production rate per well | 237.8 | 338.6 | 8 |
| Facilities cost per kbbl/d | 233.5 | 334.0 | 9 |
| Facilities fixed cost | 239.1 | 321.8 | 10 |
| Development well cost | 243.2 | 321.9 | 11 |
| Formation volume factor | 251.9 | 329.2 | 12 |
How to read these results
- EMV is the average Prospect NPV over all simulated wells, dry holes included. A positive EMV means that drilling adds value on average, even though most individual wells lose money.
- The most likely single outcome is a dry hole, so the median Prospect NPV is simply the cost of the well. Judge the prospect by its EMV and by the downside the company can afford — not by the median.
- Success-case figures describe a discovery before the chance of success is applied. The petroleum convention is used: P90 is the low case (90% chance of being exceeded) and P10 the high case.
- Value drivers at the top of the ranking are where appraisal data or better estimates would most reduce the uncertainty about a discovery's value.
- Precision: with 10,000 samples, the probability of a commercial discovery is estimated to within about ±0.9 percentage points (95% confidence). For tornado, spider and scatter plots of any input or output, open the ModelRisk Results Viewer.
See it move. Open the workbook, change an input on the Inputs sheet and run the simulation: every table and chart on this page updates in Excel.
Inputs and assumptions
Every assumption in the model, with its uncertainty and where it comes from. The figures are illustrative.
Geological chance of success 4 inputs
Probability that each element needed for an oil accumulation is present. Treated as independent; their product is the geological chance of success, Pg.
| Assumption | Unit | Value |
|---|---|---|
| Source rock and chargeProven oil-prone source rock in the basin; migration into this closure is the main doubt. | probability | 80% |
| Reservoir presence and qualityShallow-marine sands seen in two offset wells 8 km away; thickness at the crest uncertain. | probability | 70% |
| Trap (closure)Four-way dip closure mapped on good-quality 3D seismic; some depth-conversion risk. | probability | 75% |
| Seal (containment)Regional shale seal; fault reactivation could breach the crest. | probability | 70% |
Volumetrics (if oil is found) 10 inputs
Inputs to the volumetric equation for oil in place and recoverable volume. They describe how big a discovery could be.
| Assumption | Unit | Uncertainty | Low | Most likely | High |
|---|---|---|---|---|---|
| Productive areaMapped closure area; P90 and P10 from the low and high depth-conversion cases. | acres | Lognormal · P90, P10 | 1,500 | – | 4,500 |
| Average net payOffset-well logs scaled to the prospect's gross-thickness map. | ft | Lognormal · P90, P10 | 35 | – | 90 |
| PorosityCore and log porosity in analogue fields. | fraction | PERT · correlated | 15.0% | 21.0% | 26.0% |
| Water saturationLog-derived saturation in offset wells; higher in poorer-quality rock. | fraction | PERT · correlated | 20.0% | 30.0% | 45.0% |
| Correlation: porosity vs water saturationBetter-quality (more porous) rock tends to hold less water. Offset-well data suggest a correlation of about -0.5. | Normal copula | Fixed · copula | −0.50 | ||
| Copula draw for porosity (U)Generated by VoseCopulaBiNormal and passed to the U argument of the distribution it correlates. Do not edit. | 0 – 1 | Calculated | 0.336 | ||
| Copula draw for water saturation (U)Both draws come from one copula, so the two inputs move together as specified. | 0 – 1 | Calculated | 0.449 | ||
| Oil formation volume factor, BoPVT data from light-oil analogues in the basin (reservoir barrels per stock-tank barrel). | rb/stb | PERT | 1.15 | 1.25 | 1.40 |
| Recovery factorAnalogue fields developed with water injection. | fraction | PERT | 20.0% | 32.0% | 45.0% |
| Barrels per acre-footUnit conversion constant (acre-feet to barrels). Do not change. | bbl/acre-ft | Fixed | 7,758 | ||
Development and production (if commercial) 8 inputs
How a commercial discovery is developed and produced: the size threshold, timing, plateau-then-decline profile and well count.
| Assumption | Unit | Uncertainty | Low | Most likely | High |
|---|---|---|---|---|---|
| Minimum economic field sizeSmallest recoverable volume worth developing here (screening study). Smaller discoveries are not developed. | MMbbl | Fixed | 20.0 | ||
| Time from discovery to first oilAppraisal, concept selection, approvals and construction. | years | Discrete | 3 | 4 | 5 |
| probability of each outcomeThe probabilities must add up to 100%. | probability | must total 100% | 30% | 50% | 20% |
| Plateau rateAnnual offtake on plateau as a share of the recoverable volume (reservoir and facility limits). | share of volume / yr | PERT | 8.0% | 10.0% | 13.0% |
| Share of volume produced before declineThe plateau ends once this share of the recoverable volume has been produced; exponential decline follows. | fraction | Fixed | 40% | ||
| First-year productionRamp-up while wells are brought on stream. | share of plateau | Fixed | 50% | ||
| Production rate per wellInitial rates of analogue wells. | kbbl/d | PERT | 2.5 | 4.0 | 5.5 |
| Water injectors per production wellWater injection for pressure support. | ratio | Fixed | 0.50 | ||
Development capex phasing 2 inputs
When the development capex is paid, in years relative to first oil (−2 = two years before).
| Assumption | Unit | Total | Uncertainty | Payment 1 | Payment 2 | Payment 3 |
|---|---|---|---|---|---|---|
| Development capex: paid in year (first oil = 0)Long-lead items and fabrication; installation and drilling; completion and commissioning. | year | Fixed · phasing | −2 | −1 | 0 | |
| share of the cost paidThe shares must add up to 100%. | share | 100% | must total 100% | 30% | 50% | 20% |
Costs (US$ million, real 2026 terms) 10 inputs
Capital, operating and abandonment costs. Development costs scale with the plateau rate; a risk event adds a possible major overrun.
| Assumption | Unit | Uncertainty | Low | Most likely | High |
|---|---|---|---|---|---|
| Exploration well (dry-hole cost)Rig rate × planned days plus services. Spent whatever the result. | US$m | PERT | 30.0 | 38.0 | 55.0 |
| Appraisal programme (if oil is found)One appraisal well and a well test, after a discovery. | US$m | PERT | 20.0 | 28.0 | 45.0 |
| Facilities: fixed costPlatform or subsea infrastructure that does not scale with production rate. | US$m | PERT | 100.0 | 140.0 | 220.0 |
| Facilities: cost per unit of capacityProcessing and export capacity. | US$m per kbbl/d | PERT | 15.0 | 20.0 | 28.0 |
| Development well costDevelopment well, drilled and completed. | US$m per well | PERT | 28.0 | 35.0 | 50.0 |
| Probability of a major cost overrunRoughly one in four offshore projects suffers a major overrun. | probability | Fixed | 25% | ||
| Overrun, if it occursExtra spend as a share of base development capex. Zero when the risk event does not occur. | share of capex | Risk event · PERT | 10.0% | 20.0% | 45.0% |
| Fixed operating costFacility operation, logistics and maintenance, paid each producing year. | share of capex / yr | Fixed | 4.0% | ||
| Variable operating costPer-barrel costs: chemicals, power, water handling and export tariff. | US$/bbl | PERT | 7.0 | 9.0 | 13.0 |
| Abandonment costDecommissioning, paid in the year after production stops. | share of capex | Fixed | 15% | ||
Oil price (Brent, real 2026 US$/bbl) 4 inputs
The price follows a mean-reverting random walk in log terms (VoseTimeGBMVR) around an uncertain long-term level.
| Assumption | Unit | Uncertainty | Low | Most likely | High |
|---|---|---|---|---|---|
| Oil price in Year 0Current Brent price. | US$/bbl | Fixed | 75.0 | ||
| Long-term oil price (level the price reverts to)Range of the company's long-term planning cases. Uncertainty about the level itself, on top of year-to-year volatility. | US$/bbl | PERT | 55.0 | 70.0 | 95.0 |
| Price volatilityStandard deviation of the annual change in log price. | per year (log) | Fixed | 25% | ||
| Mean-reversion factorShare of the gap to the long-term level closed each year (between 0 and 1). | per year | Fixed | 0.35 | ||
Fiscal terms and economics 4 inputs
Illustrative concession terms; cash flows are discounted at a real hurdle rate.
| Assumption | Unit | Value |
|---|---|---|
| Royalty ratePaid on gross oil revenue. | share of revenue | 10% |
| Corporate income tax rateDevelopment capex is expensed immediately; tax losses are carried forward without limit. | share of profit | 30% |
| Discount rate (real)Company hurdle rate for exploration investments. | per year | 10.0% |
| Calendar year of Year 0The exploration well is drilled in Year 0. | year | 2027 |
Units and conventions
- Money
- US$ million in real (2026) terms; costs are negative in the cash flow.
- Volumes
- MMbbl = million barrels; MMstb = million stock-tank barrels; kbbl/d = thousand barrels per day.
- Percentiles
- Petroleum convention: P90 is the low estimate (90% chance of being exceeded), P10 the high estimate.
- Timing
- Year 0 is the exploration well. Annual cash flows are discounted mid-year to the start of Year 0.
Key assumptions and limitations
- Chance
- Risk factors are independent fixed probabilities; there is no uncertainty about Pg itself.
- Appraisal
- Appraisal reveals the true volume, and the development decision uses the minimum economic field size rather than a full value-of-information analysis.
- Tax
- Stand-alone, ring-fenced project: exploration and appraisal costs are not offset against tax; development capex is expensed immediately.
- Scope
- Oil only, real terms, no hedging; operating costs do not move with the oil price.
- Data
- All figures are illustrative. Kestrel is not a real prospect.
How to use it
- Review the assumptions on the Inputs sheet and change the yellow cells to reflect your own prospect. Everything else is calculated.
- Press F9 a few times and watch the Prospect and Cash flow sheets: each recalculation is one possible outcome of drilling the well.
- Run a simulation from the ModelRisk ribbon. The model is set to 10,000 samples with a fixed seed, so the results are reproducible.
- Read the Results sheet; it fills in automatically. Open the ModelRisk Results Viewer for tornado, spider and scatter plots of any input or output.
- Save the workbook under a new name before adapting it. The Model checks at the bottom of the Cash flow sheet should all read OK.
Simulate this model with ModelRisk’s classic engine: it does not run in Turbo mode yet.
ModelRisk functions used
- VoseBernoulli
- Whether the well finds oil.
- VoseLognormalAlt
- Area and net pay, entered as P90 and P10 estimates.
- VosePERT
- Expert three-point estimates (minimum, most likely, maximum).
- VoseCopulaBiNormal
- Correlates porosity and water saturation through the U argument of their distributions.
- VoseDiscrete
- Time from discovery to first oil.
- VoseRiskEvent, VosePERTObject
- A possible major cost overrun: probability of occurrence and size if it occurs.
- VoseTimeGBMVR
- A mean-reverting oil price path over 30 years (array function).
- VoseInput, VoseOutput
- Name the uncertain inputs and the key outputs for the Results Viewer and sensitivity analysis.
- VoseSimMean, VoseSimPercentile, VoseSimProbability
- Bring simulation statistics back into the workbook on the Results sheet.
- VoseSimSensitivityMean
- The tornado chart: the twelve VoseInputs that move the mean development NPV most across their range, ranked.
Further reading
- Sensitivity analysis in Excel: a tornado chart step by step (Vose guide)
- Vose, D. (2008). Risk Analysis: A Quantitative Guide, 3rd edition. Wiley.
- Rose, P. R. (2001). Risk Analysis and Management of Petroleum Exploration Ventures. AAPG Methods in Exploration 12.
- SPE / WPC / AAPG / SPEE / SEG / SPWLA / EAGE (2018). Petroleum Resources Management System (PRMS).
- Time series ▸ VoseTimeGBMVR; Modeling correlation ▸ copulas; Simulation results functions.
Download the workbook and run it yourself. It opens in Excel with ModelRisk. The free trial runs every example model.
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An illustrative example: the figures are invented for teaching and do not describe a real company, project or asset. Last updated 9 October 2026.