## Simulation

Exploration prospect evaluations differ from many other investment analyses, because they are entirely dependent on an uncertain event- a hydrocarbon discovery that meets the threshold of being commercial. Prior to drilling, due to this uncertain event, any analysis is inherently speculative. Sometimes seismic data can suggest the presence of hydrocarbons, however true discovery occurs only by drilling wells and running tests .

The common benchmarks for evaluation of any project are net present value (NPV), discounted cash flow rate of return (DCF-ROI), present value index (PVI), and payout. Payout can be based on discounted or undiscounted cash flows.

In theory, investments should be made in accordance to the “cost-benefit” ratio to maximize asset returns. Thus acquisitions should be made with the projects with the highest present value index (NPV/Investments). This simple concept is difficult to apply when a project proceeds in a series of stages, and each stage is contingent on success of the previous stage.

The means of investing in exploration areas are numerous. They include acquisitions, farm-ins and competitive bidding for exploration acreage In all cases, there are large upfront costs and uncertainty. Companies can limit their exposure to the large initial exploration costs by forming operator groups composed of a number of partners.

Investment analysis of oil/gas ventures exists in a microcosm of an industry experiencing an incredible transformation. It was recognized in the 1990’s that new drivers would play an increasing role in the future exploration efforts. The “Drivers of Change” enumerated in reference 1 (1994) have all come to fruition:

• Volatility of Oil Prices

• De-integration of upstream resources and downstream sources

• New technology – principally 3-D seismic, horizontal drilling, and tension leg platforms (deep sea exploration)

• Communication revolution

• Political transformation and breakdown of national frontiers

• Growing global environment awareness

• Ownership and governance –Expanded state sponsored NOC investments

• De-regulation

The most powerful drivers for the 21st Century are growing global environment awareness and new technology. This awareness that companies needed to examine every opportunity in the world and the new technology for deep water exploration translated into a future of need for large well funded and international oil companies. This lead to nearly a decade of mega-mergers.

The impact on this structural transformation meant : a) More competition for the high value exploration blocks around the globe with NOC b) Major oil companies interested in operating the block, rather than being participant, and c) A few mega-service companies partnering with the oil companies at every phase of exploration and production in every location where E&P exists.

Exploratory prospect evaluation requires risk evaluation. There is no single method for analysis.

The probability of the existence of hydrocarbons in a play depends on:

1) Confinement or closure of the deposit

2) Adequate deposition of organic material to form oil

3) Right conditions (time, pressure and temperature) to become oil or gas

If each factor is assigned a probability, then

Often this is referred to as the “geological risk.” This does not describe the chance of a commercial discovery. For a commercial discovery, the discovered accumulation must meet certain threshold criteria:

1) Sufficient quantity of recoverable hydrocarbons (HC)

2) Reservoir productivity is sufficient to produce hydrocarbons at commercial (economic) rates

3) Hydrocarbon discovered is commercially marketable- this may rule out a large gas, condensate, or volatile oil discovery as being commercial. Also, heavy oils discovered offshore may be considered non-commercial.

Some economic analyses will lump these factors into a “commerciality risk factor”. However if possible, it is worthwhile to identify each one separately.

Now, consider that the chance of success of each of these six factors is 95% or a 1 in 20 chance of being absent. The chance of hydrocarbons being present is 86%, but the chance of a commercial discovery is 74%. If all factors are 50%, the chance of hydrocarbons drops to 12.5% or 1:8, and the chance of a commercial discovery is 1.5%. If in this example, we can eliminate the chance that the hydrocarbon is marketable, the chance of a commercial discovery now is 3% or 1:33.

Now, an exploration program of a block will typically involve more than one well, so the chances of one or more successes will in theory, increase as exploration program continues. The probability of having one success after “n” wells are drilled, each with a success probability, , can be calculated using the binomial distribution.

The expected recoverable oil in an accumulation hydrocarbons as risked is:

Classical risk analysis assigns probability distributions to the variables, including . Typically, the triangular distributions are used.Triangular distribution are simple to understand and provide a limited domain for the random variable. Other distributions such as the uniform and normal can be used. From Monte-Carlo simulation, a distribution of can be generated.

Given and recoverable oil, the expected reserves for the discovered hypothetical field within the block can be calculated.

At this point, it is necessary to construct various scenarios to identify an expected return on the prospect. If the contract establishes a mandatory exploratory program, then this is given in our model as a 100% certainty cost, along with signature bonus. If no oil is found, then this establishes our “unsuccessful scenario” or maximum loss.

The “success case” may involve numerous evaluations, considering various drilling costs and facility costs. Ultimately, each of these scenarios must be assigned a probability.

Under a Production Sharing Contract, cost recovery provisions allow an Operator to achieve a more rapid payout of the investment, however as the project becomes more profitable, the PSC mandates that a greater share of revenues go to the government.

The economic evaluations of the various scenarios are very important as they identify the full range of economic gain and loss. The private oil company, may after examining the potential for disaster, not proceed unless it can reduce its working interest.

The risk factor approach has a number of weaknesses, including: a) estimation of probabilities and distributions are highly subjective and b) each risk factor is considered to be independent and stationary (time invariant) contrary to the nature of the factors. To improve the quality of estimation, companies often rely on outside geologic and seismic consultants, to provide additional opinions.

The assumption of independence of variables is done to simplify analysis. The short comings of this form of analysis should be recognized early on. As a real world example, an exploratory block in Brazil had shown to have an extensive structure based on seismic. As there was no prior wells, the seismic structural map was in time units. As the drilling progressed, the sands became increasingly more compacted with no signs of hydrocarbons. The top of target was continually prognosticated to be considerably deeper due to the higher velocities. Drilling costs rose due to compaction. The well’s chance of success was quickly diminishing due to the interaction between risk factors.

At times, the interdependence of risk factors is responsible for positive results. A high porosity will impact the quantity of oil found and improves the productivity of the well.

Monte-Carlo simulation can be performed using correlated variables (Crystal Ball software, Reference 5). This may be helpful in the economic simulation of prospects. A higher oil price forecast is correlated with higher drilling costs, and facility costs.

- Time invariance

The binomial distribution works when the success probability is a fixed value. There is a philosophical argument of whether, with more exploratory drilling, we will: a) become more successful, because every dry hole shows us our errors or b) become less successful, because we progressively explore the less prospective structures.

Both perspectives have merit. However, with improved seismic techniques, the latter argument of progressively less prospective structures, I believe, holds more support.

Decision tree diagrams can be used either as an alternative or to complement Monte-Carlo studies. It is a very effective tool in showing risks. Reference 3 shows many ways to construct diagrams to describe economic analyses. Sensitivity analyses, including best/ worse case scenarios and impact of variables, provides added insight to the analyses.

An approach of calculating “thresholds” in modelling economics also adds insight. If a project is uneconomic, under what conditions might we consider it to be economic. What possible changes can be made to the Production Sharing Contract (PSC) terms to make exploration (or production related projects) economical. I call this “reversing the question.”

Exploration decisions do not rely on a few simple metrics. To maximize assets, one should choose investments in accordance to the NPV/ investment or PVI. In comparing two prospects, one with an expected PVI of 2 and a second one with a PVI of 1.6, an Operator opts for the lower PVI. Why? The investment of the higher PVI and the potential loss is much higher. The Operator is risk averse. The role of “risk acceptance/ aversion” is part of utility theory.

This concept is very important The expected economic returns do not tell the full story. An investment without sufficient back away provisions can cause the company severe economic hardship. The Operator has perhaps looked beyond the prospect area, and considered exogenous variables- how have other Operators in similar prospects fared?

If the economic analysis has considered fields sizes with upside reserves of > 1 billion barrels, the analyses is suspect. An alternative analysis is to examine the chance of success and the size of fields discovered in “analogous” areas. I put the term analogous in quotes, because I know how difficult it is to consider a different geological area as being analogous.

Signature bonuses and royalties can be demanded by the host country. The host country is, in effect, ensuring itself against failure, but this can reduce competition for bids.

Certain provisions of a PSC may be modified through negotiations. The host country has multiple objectives. The PSC typically has extension/renewal provisions, however if the Operator is particularly successful, the NOC is highly motivated to take over operations. A PSC should contain provisions to train nationals in the eventual transfer to operate the fields. A lengthy transition of several years may be very beneficial to both the Operator and NOC.

The Operator is generally in the best position to continue exploration at the end of a contract. It is incumbent for the Operator to prove to the host country that it will make the NOC a full partner in this effort. Restoration and abandonment considerations are very important. Gas discoveries for offshore fields is an area that I believe will become an increasingly “hot area” for PSC’s. The provisions of a PCS must be very carefully written to prevent the national government to demand certain sales price that will deny the Operator’s right to a return on their investment.

The common benchmarks for evaluation of any project are net present value (NPV), discounted cash flow rate of return (DCF-ROI), present value index (PVI), and payout. Payout can be based on discounted or undiscounted cash flows.

In theory, investments should be made in accordance to the “cost-benefit” ratio to maximize asset returns. Thus acquisitions should be made with the projects with the highest present value index (NPV/Investments). This simple concept is difficult to apply when a project proceeds in a series of stages, and each stage is contingent on success of the previous stage.

The means of investing in exploration areas are numerous. They include acquisitions, farm-ins and competitive bidding for exploration acreage In all cases, there are large upfront costs and uncertainty. Companies can limit their exposure to the large initial exploration costs by forming operator groups composed of a number of partners.

Investment analysis of oil/gas ventures exists in a microcosm of an industry experiencing an incredible transformation. It was recognized in the 1990’s that new drivers would play an increasing role in the future exploration efforts. The “Drivers of Change” enumerated in reference 1 (1994) have all come to fruition:

• Volatility of Oil Prices

• De-integration of upstream resources and downstream sources

• New technology – principally 3-D seismic, horizontal drilling, and tension leg platforms (deep sea exploration)

• Communication revolution

• Political transformation and breakdown of national frontiers

• Growing global environment awareness

• Ownership and governance –Expanded state sponsored NOC investments

• De-regulation

The most powerful drivers for the 21st Century are growing global environment awareness and new technology. This awareness that companies needed to examine every opportunity in the world and the new technology for deep water exploration translated into a future of need for large well funded and international oil companies. This lead to nearly a decade of mega-mergers.

The impact on this structural transformation meant : a) More competition for the high value exploration blocks around the globe with NOC b) Major oil companies interested in operating the block, rather than being participant, and c) A few mega-service companies partnering with the oil companies at every phase of exploration and production in every location where E&P exists.

**Evaluation of Exploratory Prospects (Classic Approach)**Exploratory prospect evaluation requires risk evaluation. There is no single method for analysis.

The probability of the existence of hydrocarbons in a play depends on:

1) Confinement or closure of the deposit

2) Adequate deposition of organic material to form oil

3) Right conditions (time, pressure and temperature) to become oil or gas

If each factor is assigned a probability, then

Often this is referred to as the “geological risk.” This does not describe the chance of a commercial discovery. For a commercial discovery, the discovered accumulation must meet certain threshold criteria:

1) Sufficient quantity of recoverable hydrocarbons (HC)

2) Reservoir productivity is sufficient to produce hydrocarbons at commercial (economic) rates

3) Hydrocarbon discovered is commercially marketable- this may rule out a large gas, condensate, or volatile oil discovery as being commercial. Also, heavy oils discovered offshore may be considered non-commercial.

Some economic analyses will lump these factors into a “commerciality risk factor”. However if possible, it is worthwhile to identify each one separately.

Now, consider that the chance of success of each of these six factors is 95% or a 1 in 20 chance of being absent. The chance of hydrocarbons being present is 86%, but the chance of a commercial discovery is 74%. If all factors are 50%, the chance of hydrocarbons drops to 12.5% or 1:8, and the chance of a commercial discovery is 1.5%. If in this example, we can eliminate the chance that the hydrocarbon is marketable, the chance of a commercial discovery now is 3% or 1:33.

Now, an exploration program of a block will typically involve more than one well, so the chances of one or more successes will in theory, increase as exploration program continues. The probability of having one success after “n” wells are drilled, each with a success probability, , can be calculated using the binomial distribution.

**Monte-Carlo Simulation to determine recoverable oil**The expected recoverable oil in an accumulation hydrocarbons as risked is:

Classical risk analysis assigns probability distributions to the variables, including . Typically, the triangular distributions are used.Triangular distribution are simple to understand and provide a limited domain for the random variable. Other distributions such as the uniform and normal can be used. From Monte-Carlo simulation, a distribution of can be generated.

Given and recoverable oil, the expected reserves for the discovered hypothetical field within the block can be calculated.

**Economic Evaluation**At this point, it is necessary to construct various scenarios to identify an expected return on the prospect. If the contract establishes a mandatory exploratory program, then this is given in our model as a 100% certainty cost, along with signature bonus. If no oil is found, then this establishes our “unsuccessful scenario” or maximum loss.

The “success case” may involve numerous evaluations, considering various drilling costs and facility costs. Ultimately, each of these scenarios must be assigned a probability.

Under a Production Sharing Contract, cost recovery provisions allow an Operator to achieve a more rapid payout of the investment, however as the project becomes more profitable, the PSC mandates that a greater share of revenues go to the government.

The economic evaluations of the various scenarios are very important as they identify the full range of economic gain and loss. The private oil company, may after examining the potential for disaster, not proceed unless it can reduce its working interest.

**Weaknesses**The risk factor approach has a number of weaknesses, including: a) estimation of probabilities and distributions are highly subjective and b) each risk factor is considered to be independent and stationary (time invariant) contrary to the nature of the factors. To improve the quality of estimation, companies often rely on outside geologic and seismic consultants, to provide additional opinions.

The assumption of independence of variables is done to simplify analysis. The short comings of this form of analysis should be recognized early on. As a real world example, an exploratory block in Brazil had shown to have an extensive structure based on seismic. As there was no prior wells, the seismic structural map was in time units. As the drilling progressed, the sands became increasingly more compacted with no signs of hydrocarbons. The top of target was continually prognosticated to be considerably deeper due to the higher velocities. Drilling costs rose due to compaction. The well’s chance of success was quickly diminishing due to the interaction between risk factors.

At times, the interdependence of risk factors is responsible for positive results. A high porosity will impact the quantity of oil found and improves the productivity of the well.

Monte-Carlo simulation can be performed using correlated variables (Crystal Ball software, Reference 5). This may be helpful in the economic simulation of prospects. A higher oil price forecast is correlated with higher drilling costs, and facility costs.

- Time invariance

The binomial distribution works when the success probability is a fixed value. There is a philosophical argument of whether, with more exploratory drilling, we will: a) become more successful, because every dry hole shows us our errors or b) become less successful, because we progressively explore the less prospective structures.

Both perspectives have merit. However, with improved seismic techniques, the latter argument of progressively less prospective structures, I believe, holds more support.

**Other approaches**Decision tree diagrams can be used either as an alternative or to complement Monte-Carlo studies. It is a very effective tool in showing risks. Reference 3 shows many ways to construct diagrams to describe economic analyses. Sensitivity analyses, including best/ worse case scenarios and impact of variables, provides added insight to the analyses.

An approach of calculating “thresholds” in modelling economics also adds insight. If a project is uneconomic, under what conditions might we consider it to be economic. What possible changes can be made to the Production Sharing Contract (PSC) terms to make exploration (or production related projects) economical. I call this “reversing the question.”

Exploration decisions do not rely on a few simple metrics. To maximize assets, one should choose investments in accordance to the NPV/ investment or PVI. In comparing two prospects, one with an expected PVI of 2 and a second one with a PVI of 1.6, an Operator opts for the lower PVI. Why? The investment of the higher PVI and the potential loss is much higher. The Operator is risk averse. The role of “risk acceptance/ aversion” is part of utility theory.

This concept is very important The expected economic returns do not tell the full story. An investment without sufficient back away provisions can cause the company severe economic hardship. The Operator has perhaps looked beyond the prospect area, and considered exogenous variables- how have other Operators in similar prospects fared?

If the economic analysis has considered fields sizes with upside reserves of > 1 billion barrels, the analyses is suspect. An alternative analysis is to examine the chance of success and the size of fields discovered in “analogous” areas. I put the term analogous in quotes, because I know how difficult it is to consider a different geological area as being analogous.

Signature bonuses and royalties can be demanded by the host country. The host country is, in effect, ensuring itself against failure, but this can reduce competition for bids.

Certain provisions of a PSC may be modified through negotiations. The host country has multiple objectives. The PSC typically has extension/renewal provisions, however if the Operator is particularly successful, the NOC is highly motivated to take over operations. A PSC should contain provisions to train nationals in the eventual transfer to operate the fields. A lengthy transition of several years may be very beneficial to both the Operator and NOC.

The Operator is generally in the best position to continue exploration at the end of a contract. It is incumbent for the Operator to prove to the host country that it will make the NOC a full partner in this effort. Restoration and abandonment considerations are very important. Gas discoveries for offshore fields is an area that I believe will become an increasingly “hot area” for PSC’s. The provisions of a PCS must be very carefully written to prevent the national government to demand certain sales price that will deny the Operator’s right to a return on their investment.