How Much Oil

The coastal plain of the Arctic National Wildlife Refuge (ANWR) is generally re- garded as the most promising region for onshore oil exploration in the USA. Congress Is currently debating whether to allow the Department of Interior (DOI) to sell leases for oil exploration and development in this environmentally unique region. In 1987 DOI released a study of the oil potential and environmental vulnerability of the ANWR which recommended unlimited leasing. The Energy Information Agency (EIA) subsequently responded with its own, con- flicting assessment of the potential of the region. The DOI and EIA estimates of oil potential differ by a factor of five. This paper presents an analysis and critique of these studies. A Monte Carlo simulation model is used to generate comparable projections of oil production using DOI and EIA data and assumptions. This model makes it possible to reconcile the previous results and to study the sensitivity of the projections to key assumptions. The paper concludes with some thoughts about the problem of determining a socially optimal development plan for the ANWR.

The author is with the Amos Tuck School of Business Administration, Dartmouth College, Hanover, NH 03755, USA.

The helpful comments of an anonymous reviewer are gratefully acknowledged.

Arctic National Wildlife Refuge

How much oil can we expect?

Stephen G. Powell

The Arctic National Wildlife Refuge (ANWR) is a 19 million acre reserve in north-eastern Alaska established by the Alaska National Interests Lands Conservation Act of 1980. Most of the Refuge was designated as wilderness by Congress and thus off limits for minerals exploration. However, a 1.5 million acre segment of the coastal plain fronting the Beaufort Sea, the so called ANWR 1002 region (after the defining section of the 1980 legislation), was reserved for further study because of its potential for significant oil and gas discoveries. Congress has the responsibility of deciding whether to open the 1002 region for oil and gas development. The decision is strongly influenced by environmental concerns since the Arctic coastal plain is a unique environment, crucial to a number of animal populations, in particular the porcupine caribou herd which migrates annually between Canada and the ANWR plain.

Two federal agencies have studied the question of how much oil and gas may be present in the ANWR 1002 region. The Department of Interior (DOI) analysed the oil and gas potential of the area in the context of a broad evaluation of the ANWR environment and its sensitivity to oil and gas development. DO1 concluded that there is a 19% chance that oil can be economically recovered from the region; the mean estimate for total oil production (conditional on positive production) was 3.2 billion barrels. The report recommends that Congress direct the Secretary of Interior to conduct an essentially unrestricted leasing programme in the 1002 region.

The Energy Information Agency (EIA) of the Department of Energy subsequently released its own evaluation of the potential of the ANWR region. EIA analysed possible patterns of future oil production from the 1002 area in more detail than did DOI, and generally took a more optimistic view of the regions promise. It estimated the volume of economically recoverable oil at 3.4 billion barrels. While the EIA report itself downplays its differences with the earlier study, the two studies in fact project widely different scenarios for future oil development in the region.

0301-4207/90/030225-14 0 1990 Butterworth-Heinemann Ltd 225

Oil resources in the Arctic National Wildlife Refuge

N.K. Clough, PC. Patton and AC. Christ- ensen. eds. Arctic National Wildlife Re- fuge, Alaska, Coastal Plain Resource Assessment, US Fish and Wildlife Service, US Geological Survey and Bureau of Land Management, Washington, DC, 1987. *Although there is some evidence that the same geologic structures that make Prudhoe Bay so productive extend through the ANWR, there is also evidence of more geologic complexity in the ANWR. This adds to the uncertainty in resource estimates. 3Although large quantities of natural gas are thought to be present in the area, it was determined that high transport costs would prevent commercial exploitation in the foreseeable future. Accordingly, we will not discuss gas potential further here.

226

The primary purpose of this paper is to develop a framework for projecting potential oil development in the ANWR within which the DO1 and EIA approaches can be compared and reconciled. This framework allows us to use the data and assumptions of either the DOI or EIA analyses and to make comparable projections over time of oil production from the ANWR. The results allow us to reconcile the important differences between these two studies and to shed light on the range of outcomes possible from ANWR development and on the risks this development would entail.

The paper is organized as follows. In the next several sections we outline the DO1 and EIA approaches to the question of ANWR potential. We then discuss the treatment of prospect and geologic risks in the two studies, assumptions which explain much of the difference between them. We then present our model for projecting ANWR oil production and the results of simulations using both the DO1 and EIA assumptions. The model is also used for sensitivity analyses, which allow us to develop a better understanding of the possible range of future outcomes. The paper closes with some ideas for further work that would help to clarify the risks and benefits of ANWR development and to delineate an optimal development plan.

DO1 resource assessment

Overview

DOIs coastal plain resource assessment is the result of five years of study of the biology and geology of the ANWR. It represents the Departments response to the requirement of the 1980 Alaska National Interest Lands Conservation Act that it study the ANWR region and recommend to the Congress a permanent management plan. The central conflict that led to the exclusion of the coastal plain (the 1002 region) from wilderness designation in 1980 was between the benefits of oil and gas development and the costs of environmental degradation. The two key questions which this report was expected to answer are:

0 How much oil and gas is present beneath the 1002 region? 0 How harmful would oil and gas development be to the plant and

animal communities there?

The ANWR 1002 area is a region roughly 100 miles wide (east to west) and 50 miles deep (south to north) along the northern Alaska coastal plain (see Figure 1). The Prudhoe Bay oil fields are approximately 75 miles west of the westernmost part of the 1002 area. This fact is significant for two reasons. First, much of the geological analysis of oil and gas potential in the region is based on analogy with the huge Prudhoe Bay discoveries.2 Second, any oil produced in the 1002 area would almost certainly be brought to the refineries by pumping it through a new east-west pipeline to the northern terminus of the existing Trans-Alaska Pipeline (TAPS) at Prudhoe Bay and from there via TAPS south to the port of Valdez.

DOIs assessment of the oil potential of the region3 began with an estimate of the quantities of oil present below the surface of the region, based solely on geological information. This oil is referred to as oil in place. Then an assessment was made of how much of this oil in place could be economically produced, based on both geologic and economic factors (eg oil quality, exploration and development costs, transport

RESOURCES POLICY September 1990


Beoufort Sea

Barrow

Alaska I I Anchorage I

\ I

-

iL / I Refuge i \ -1 i i

\ i/ i

lJer

p-4 -.-.

I e 0 50 100 miles i&f /- 1

Scale

Figure 1. ANWR and its location in Alaska (Source: US Congress Office of Technology Assessment, Oil Production in the Arctic National Wildlife Refuge: The Technology and the Alaskan Oil Context, OTA-E-394, US Government Printing Office, Washington, DC, 1988.)

costs, oil price etc). This oil is referred to as economically producible oil. Since the methods used in these two assessments were different, we will discuss them separately.

Oil in place

DOIs estimate of oil in place is based on several sources of information. Several areas on the Alaskan coastal plain have been drilled, including Prudhoe Bay and the National Petroleum Reserve farther west. These exploration and development activities have led to a general understanding of the geologic structure of the coastal plain. However, no drilling has occurred within the 1002 area itself (although one test well has been drilled on native lands just north of the 1002 area; the results of this test by private companies are not public). A second source of information is a set of seismic surveys carried out by private industry and made available to DOI.

These data led DO1 to identify 26 prospects in the 1002 area. Each prospect is an area on the surface from which one can drill to potentially oil rich strata. These potentially oil bearing strata are known as plays. DO1 identified seven plays in the 1002. Clearly, the same geological stratum can be reached from more than one point on the surface. Prospects and plays are important here because DO1 used a play analysis to assess oil in place and a prospect analysis to assess economically producible oil.

Although the general outlines of DOIs method of determining oil in place are clear, the details were deliberately concealed because the data are proprietary to private industry. All we can say is that DO1 analysed the geologic characteristics of each of the seven plays identified, including potential sources of petroleum and the existence of traps and

RESOURCES POLICY September 1990 227

0 10 20 30 Prudhoe Bay fields. This difference in interpretation of the geologic

40 50

Billion ba&els

data underlines the uncertainty surrounding the oil potential of the ANWR.

Figure 2. Oil in place (DOI). Economically producible oil

One of the crucial parameters determining the presence of oil in a prospect is the prospect risk, which is the probability that the prospect will contain no oil when drilled. DO1 estimated the prospect risk in the ANWR at 93%; that is, each prospect has a 93% chance of containing no oil. DO1 assumed that these risks were independent from one prospect to the next. Furthermore, in assessing producible oil DO1 analysed the potential of only the five largest prospects, rather than all 26. DO1 justified this on the grounds that, given the location of the area, no oil can be produced unless a large find is made, and a large find will most probably come from one of the largest prospects. We will discuss prospects risks and related issues more thoroughly in a later section.

Within PRESTO II each prospect is described by a number of parameters. First, each prospect is associated with one or more potentially oil bearing zones. These zones are essentially identical to the plays

4J.J. Hansen and R.W. Kornbrath, Re- source Appraisal Simulation for Petroleum

identified in the first phase of the study. Each zone, in turn, is described

in the Arctic National Wildlife Refu.qe, Alas- in geologic terms as having an area1 extent (in acres), thickness (in feet)

ka, State of Alaska, Department of Natural and oil volume (per acre-foot). All of these parameters are known Resources, Division of Geoloaical and Geophysical Survey, Profession>1 Report

imprecisely, so they are input into the model in the form of probability

90, 1986. distributions. On each run of the simulation estimates are made for each

5L.W. Cooke, Estimates of Undiscovered, of these parameters and the total oil recoverable from the prospect is Economically Recoverable Oil and Gas Resources for the Outer Continental Shelf

determined by multiplying the estimated volume of the zone by the oil

as of&/y 7984. US Department of Interior, volume factor. Total recoverable oil for the prospect is the sum of these

Minerals Management Service, 1985. amounts over all zones in the prospect.


reservoirs. The results are summarized in a probabilistic description of oil in place (Figure 2). DO1 estimates that total oil in place for the 1002 region will not exceed 40 billion barrels and the chances are roughly even that it will fall above or below 12 billion barrels.

The only alternative source of information on the geologic potential of the ANWR is a 1986 report from the state of Alaska.4 This study uses a methodology similar to the DO1 study, but reports a mean value for oil in place of 7.22 billion barrels, around half the DO1 mean value. This difference is attributable primarily to a difference in the interpretation of a single play, the Ellesmerian. The state report attributes 1.13 billion barrels to the Ellesmerian while DO1 attributes over 7 billion. The Ellesmerian has the same geologic structure as the source of the major

The second phase of the DO1 assessment takes as given the probabilistic description of oil in place and estimates the volume of oil that might be economically recovered from the region. This estimation procedure relies on a Monte Carlo simulation model known as PRESTO II. PRESTO II is used to simulate an exploratory drilling programme for the 1002 region, based on a stylized view of the geology of the region and the economics of oil development there. For the purposes of the DO1 study it was assumed that any oil discovered in the region would be found under one of the 26 prospects identified through seismic surveys. These are all large structures, much larger, in fact, than the smallest structures considered in the oil in place estimation procedure. But the authors felt that successful development of the region would require at least one large find and the 26 prospects represented the likeliest places to make such a find.

220 RESOURCES POLICY September 1990

Billion barrels

Figure 3. Conditional producible oil (DOI).

The MEFS was determined in a separate study: J.S. Young and W.S. Hauser, Eco- nomics of Oil and Gas Production for ANWR for the Determination of Minimum Economic Field Size, Bureau of Land Man- agement, Alaska St&e Office, Division of Mineral Resources, 1987. 7A growth rate of 1% per year in prices was assumed. Energy Information Agency, Potential Oil Production from the Coastal Plain of the Arctic National Wildlife Refuge, 1987. Other studies of the potential of the ANWR include W.T. Goerold, Environ- mental and petroleum conflicts: a simulation model to determine the benefits of petroleum production in the Arctic National Wildlife Refuge, Alaska, Materials and Society, Vol 2, No 3, 1987, pp 279-307; W.T. Goerold, A simulation model to determine the probability of finding economically producible petroleum in the Arctic National Wildlife Refuge (ANWR), Alaska, Proceedings, Tenth Annual North Amer- ican Conference, International Association for Energy Economics, Houston, TX, 1988, pp 387-398; and US Conoress, Office of Technology Assessment, oil Production in the Arctic National Wildlife Refuge: The Technolcgy and the Alaskan Oil Context, OTA-E-394. US Government Printino Office, Washington, DC, 1988.



The calculation of economically recoverable oil for the 1002 region requires one more set of inputs. These have to do with the economic characteristics of oil production in the region, and are summarized in the minimum economic field size (MEFS). The idea behind a MEFS is that in any region there is a field that is just large enough to justify the necessary expenditures for oil recovery, transport and logistics. This minimum size depends on, among factors, the price at which oil can be sold. In the DO1 study the MEFS was calculated to be 440 million barrels,6 based on the known and conjectured geologic characteristics of the 1002 region, and an oil price in the year 2000 of $33/barrel in 1984 dollars. However, the MEFS is acknowledged to be highly sensitive to the price of oil, ranging from 2 billion barrels for a price of $22 to 150 million barrels for a price of $40.

The results of DOTs analysis of economically producible oil are shown in Figure 3. This graph shows the amount of oil potentially recoverable from the 1002 region, if any oil is recovered at all. The figure shows a maximum volume of 22 billion barrels. The median falls at 2.21 billion, indicating an even chance that producible quantities will exceed or fall below that amount. The mean value is 3.23 billion barrels, which is somewhat above the median because the distribution is skewed to the right. It should be stressed that these quantities are conditional on the discovery of any producible oil, an event that has only a 19% probability of occurring. If we take this likelihood into account, the single number that is most representative is the unconditional mean value for producible oil. This is 614 million barrels: 19% of 3.23 billion barrels.

EIA resource assessment

Overview

The EIA assessment,8 which was motivated by a request from Senator Murkowski of Alaska, is both a critique of the DO1 ANWR analysis and an independent study of a number of issues related to oil development in the 1002 region. Senator Murkowski requested an evaluation of the DO1 oil in place and producible oil estimates and a projection of probable rates of oil production over time. Thus the EIA report goes beyond the DO1 report in some respects, especially in providing projections of oil production over time. These projections make it possible to consider a number of important questions not addressed in the

0

0

0

DO1 report. These include:

Will the TAPS pipelines have sufficient capacity to transport oil produced from the ANWR? What will be the level of oil production from the rest of the USA when ANWR comes on line? How strongly is the present value of oil revenues from the 1002 region affected by discount and inflation rates?

The EIA study consists of three major elements. First is an evaluation of the DO1 estimates of oil in place, which EIA essentially accepts. Second, the report evaluates the DOI estimates of producible oil and finds them overly conservative, replacing them with its own estimates based on an average recovery factor. Finally, projections of annual production from the 1002 region are developed from the estimated volumes of total producible oil. The approach taken by EIA here was to


make assumptions about the date at which development would begin in the 1002, the total amount of oil found, the sizes of fields in which oil was found, and the rates of production over time from those fields. These assumptions allow EIA to make projections of oil production over time from the ANWR and to consider the impact of these flows on both the TAPS pipeline and total US production.

Any assessment of the potential of the ANWR must begin with an evaluation of the total amount of oil in the region. EIA reports conducting an independent evaluation of the 26 prospects identified by DOI, the results of which show a maximum value of 34 billion barrels of oil in place. This corresponds roughly to the maximum value reported by the DOI. As a result, EIA accepted the DOIs probability distribution for oil in place (Figure 2).

While it accepted the DO1 numbers for oil in place, EIA found fault with the methods used and the results reached by DO1 in determining that portion of the oil in place which could be economically produced. The EIA critique focuses on three points:

1. DO1 considered only the 26 prospects it could identify on the basis of a coarse seismic survey. Oil may well be found and produced from smaller structures once further exploration has taken place and transport infrastructure is built.

2. DO1 included only the 5 largest of the 26 prospects in its analysis of producible oil.

3. DO1 assessed the MEFS for each field at 440 million barrels; this is too high because development costs have fallen since the DO1 study was done; the estimate erroneously includes sunk costs; and it overlooks the probability that successive fields will share transport infrastructure so that the effective MEFS drops as productive fields are discovered.

Economically producible oil

Based on this critique of the DO1 approach, EIA proceeded to develop its own projections for economically producible oil. The method used was to assume that whatever the actual level of oil in place, exploration and development would eventually result in 25% of that oil being produced. This 25% oil recovery factor was chosen as conservatively representative of past experience with large oil fields. For comparison, the EIA report notes that the supergiant field at Prudhoe Bay may well achieve an ultimate recovery factor of 50%. The resulting distribution for producible oil has precisely the shape of the DO1 oil in place distribution (Figure 2), with the values on the horizontal axis shrunk by one-quarter due to the 25% recovery factor. The mean value of this distribution is 3.45 billion barrels. The assumption of a 25% recovery factor for all oil in place means there is a zero probability that no oil will be produced from the ANWR.

The EIA report offers a comparison (Table 1, p 18) between its estimates of producible oil and those of DOI. In this comparison it appears that the two studies lead to similar conclusions, since DO1 shows a mean value of 3.23 billion barrels and EIA a corresponding value of 3.45 billion. However, this comparison is extremely misleading. DO1 reports a 19% probability of successful development of the ANWR. Should this event occur, DO1 estimates the volume of production at 3.23 billion barrels. If we take both possibilities into account, successful and unsuccessful development, the overall mean value for



Table 1. EIA field size assumptions (billion barrels).

Low Mean High Field oil case oil case oil case

1 0.70 2.00 3.50 2 0.50 1 .oo 2.00 3 0.45 0.75 4 0.60 5 0.50 Total recovered 1.20 3.45 7.35

It is worth noting that no oil has been found to date in the National Petroleum Reserve Alaska, west of Prudhoe Bay, despite earlier estimates of a 97% chance of finding producible oil there.

production is 81% of zero barrels plus 19% of 3.23 billion, or 614 million barrels. Under the EIA assumption of a 25% recovery factor, there is a zero probability of unsuccessful development. lo Thus the EIA estimate of 3.45 billion barrels of producible oil is more than five times the comparable estimate from DOI.

It is important to understand the significance of this difference between the two studies. The EIA report criticizes the DO1 study for overestimating the probability of there being no recoverable oil in the 1002 area for the three reasons cited above. However, EIA does not offer an analysis of this probability at the depth of detail or sophistica- tion of the DO1 study. Instead, the EIA study uses the assumption that 25% of oil in place will be produced regardless of the actual amount of oil available or the other factors which influence the MEFS. The effect of this assumption is to eliminate the probability that no oil is produced, which is the single most important factor in the DO1 study. In the following section we will present model results that will allow us to quantify the significance of this difference in approach.

Production over time

As we pointed out above the EIA analysis goes beyond the DO1 study by projecting annual oil production from the 1002. In order to make these projections EIA made a series of assumptions. First, they chose three points on the distribution for recoverable oil to represent three possible scenarios. The points they chose were the 5th fractile, the mean and the 95th fractile. At those points the corresponding values for economically recoverable oil were 1.20, 3.45 and 7.35 billion barrels respectively. For each of these scenarios EIA then assumed that the total oil recovered would come from a certain number of fields, each with a given size. For example, in the low case the 1.20 billion barrels would come from two fields, one with 0.7 and one with 0.5 billion barrels. Table 1 shows the number of fields and their sizes for each of the three cases.

Three additional assumptions were made. One concerns the rate at which oil field production changes over time. EIA assumed that it takes a year or two for production to reach its maximum level, after which production declines geometrically. The maximum levels of production were between 5% and 9% of ultimate production, increasing with the size of the field. All fields were assumed to decline at 12% per year after the peak level was reached. The second assumption concerns the date at which initial production from the ANWR will start. Again, the EIA chose three scenarios, resulting in start dates of 1995, 2000 and 2010. Finally, EIA assumed that regardless of the total amount of oil recovered, the fields would be discovered in order of size from largest to smallest, with a two-year interval between discoveries.

The results of the EIA approach are shown in Figure 4. This figure shows how production from the 1002 region will augment oil production from other regions of the USA. The first thing to notice in the graph is that total US production is projected to decline below 6 million barrels per day by the year 2000. The three curves show potential ANWR production as an addition to other domestic production for EIAs three cases for ultimate recovery. Under the assumptions of the EIA study, in two of the three cases ANWR production reverses the decline in total US production for several years. In the low oil case ANWR production in its peak year represents 5% of total domestic production; the



Or corresponding figures are 13% for the mean case and 22% for the high oil case. This figure illustrates why the oil industry has placed such a high priority on leasing the ANWR. It may represent the last great hope for offsetting the decline in US oil production and the corresponding rise in US imports.

9

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1985 1995 2005 2015

Figure 4. Total US output and potential ANWR output (EIA).

232

Geologic and prospect risks

Much of the difference between the EIA and DO1 studies centres on the probability that no oil will be produced from the ANWR. In this section we analyse the assumptions made in the two studies that affect this crucial result.

In the DO1 study the assumption was made that of the 26 prospects identified only the largest 5 would be considered in the determination of producible oil. The rationale was that only a prospect as large as one of these five could support the infrastructure necessary for profitable development. The procedure used by DO1 to determine the distribution of producible oil can be described as follows. First, each of the five major prospects was assigned a prospect (or dry hole) risk of roughly 93%. This is the unconditional probability that no oil will be found in each of these prospects. In the Monte Carlo simulation used by DO1 the first step on each trial was to assess the status of each of the prospects: does it contain oil or is it a dry hole? For those that contain oil on a given trial, the simulation proceeds to asses the amount of oil by volumetric means. Next, a MEFS cut off is applied, to reflect the importance of the size of a field to its economic viability. Discoveries below the MEFS were treated as dry holes. The final result is a distribution for producible oil that reflects both the geology and the economics of the region.

As we have stated, the prospect risk is the unconditional probability that a prospect is dry. If (along with DOI) we assume statistical independence between the events that prospect A is dry and Prospect B is dry for all pairs of prospects, we can calculate the probability that all of the five prospects, and therefore the entire region, contains no oil. This probability, which we will call the geologic risk, is 70%: 0.935. Thus the DO1 study implies that the probability of finding oil in the ANWR is 30%. But the study also reports that the probability of producing oil is only 19%. Why is this probability less than the geologic risk? Recall that the geologic risk only reflects the geology of the region. It does not reflect the probability that oil will be discovered in amounts that are below the MEFS and are therefore not economic to produce. The conditional probability of finding quantities of oil in one or more of the five prospects in excess of the MEFS, given that oil has been found in at least one prospect, is estimated by DO1 to be 63%. Thus the probability of finding economically producible oil is 19% (63% of 30%).

It is worth pausing for a moment to examine the implications of the DO1 assumptions that only the five largest prospects matter and each has an independent prospect risk of 93%. If all 26 prospects had an unconditional probability of being dry of 93%, and the probability of any one being dry was independent of the probability of any other being dry, then the geologic risk would be 15% (0.9326). If only 10 prospects were included the geologic risk would be 48% ; if 15, it would be 34%. Thus, depending on the number of prospects included, the geologic risk can lie between 15% and 70%.

If we relax the assumption of independence between prospects we can

RESOURCES POLICY September 1990


stretch this range further. It is, after all, implausible that these prospects are independent, since they are located in the same area and share the same plays in many cases. Thus the probability that prospect B is dry is very likely to go up once we drill prospect A and find it to be dry. The more closely related the prospects are in their geology, the more these revised probabilities will change. If, in the extreme case, all prospects shared a single play, and drilling one prospect removed all uncertainty about the status of the remaining plays (so the conditional probability of a dry hole at any prospect after one dry hole has been drilled is 1 .O), the geologic risk would be 93%. This is clearly an extreme case of dependence. The upper limit on the geologic risk must therefore be somewhat below 93%.

We have discussed these risks in detail, partly to explain some of the more arcane results of the studies under consideration, but also to put the EIA assumptions in perspective. Recall that the EIA study accepted the DO1 description of oil in place and then assumed a uniform 25% recovery factor for producible oil. This amounts to assuming both a geological risk of 0% and a MEFS of zero barrels. Stated another way, the EIA method makes possible the (presumably profitable) production of small quantities of oil, while the DO1 study sets a lower limit of 440 million barrels on oil produced. The assumption of a geologic risk of zero should be contrasted with the risk of 15% that results from assuming all 26 prospects are drilled with an independent prospect risk of 93%. The EIA assumption demands either that there be more prospects in the ANWR than identified by the DO1 or that the risks at each prospect are lower than assessed by DOI.

A Monte Carlo analysis of ANWR production

Model structure

As we have seen, the DO1 and EIA take substantially different approaches to the problem of determining potential oil production from the ANWR. Since these studies differ not only in their basic assumptions but also in the nature of their final results, it is difficult to compare them. In order to facilitate this comparison, and also to shed light on the broader issues of the risks inherent in development of the 1002 region, we have developed a Monte Carlo simulation model for projecting annual rates of production from the ANWR. Our model allows us to carry out analyses of potential oil production at the same level of detail as the EIA study, but with alternative sets of inputs.

The structure of the model is quite simple. The basic input is a probability distribution for oil in place (or for some purposes producible oil) in the 1002 region. In each run of a simulation a single value is chosen randomly from this distribution. The model then calculates how much of this oil is economically producible. Next this producible oil is distributed into a number of fields of given sizes. Both the number of fields and their sizes depend on the volume of recoverable oil. Once the size and number of fields are known, production profiles are applied to project annual production from each field. We adopt the EIA assumption that fields are discovered in decreasing order by size and with a two-year delay. Each run of a simulation results in an oil production profile over time. A complete simulation gives a probabilistic description of this time profile.

In order to determine the number of fields and their sizes for any


Oil resources in the Arcric National Wildlife Refuge

Table 2. Field size assumptions.

Recoverable oil Less More (billion barrels) than 3 3-6 than 6

Number of fields 2 3 5 Field sizes (% of producible) 1 56 56 46 2 42 29 27 3 13 10 4 6 5 7 Total 100% 100% 100%

value of producible oil we followed the methods of the EIA report. Table 2 shows the number of fields and their sizes for three ranges of total recoverable oil.

The final set of assumptions in our model concerns production profiles from given fields. Again, we follow the general approach of the EIA report. Three size classes of fields are distinguished, each with a different production profile. In general, larger fields ramp up slower and reach a lower maximum level of production (in percentage terms) than smaller fields. Production from all fields declines at 12% per year after the peak. Table 3 gives the details.

We should point out that this model, like the EIA and DO1 models, is highly stylized. It is not intended to be a realistic model of the actual exploration, development and production process likely to occur in the ANWR. It is deliberately kept simple in order to facilitate a comparison with the previous approaches.

Simulation of DOI assumptions

We will first discuss the results of an exercise in which we take as given the DO1 estimates for oil in place and economically producible oil, and develop projections of annual oil output which can be compared to the EIA results. The first step is to incorporate the geologic risk, which (again) is the probability the entire region contains no oil. The DO1 study estimates this probability at 70%. Thus in 70% of the simulation runs no oil is found. In the remaining 30% of the runs the amount of producible oil is sampled from the DO1 distribution (Figure 3). Once a sample value for producible oil is found the simulation parcels this oil out into the appropriate number and size of fields as given in the tables above. Then the oil in these fields is produced at the rates cited above and total annual output is calculated. This process is repeated 5 000 times to generate probability distributions for total production and annual production over the first 25 years of development.

The results of this simulation are displayed in Figure 5, which shows the time path of oil output. This graph shows the mean value for output over time, as well as the 95th percentile values. The mean annual production reaches a maximum of around 129 thousand barrels per day in the fifth year of production. By way of comparison, peak output from the Prudhoe Bay fields was in excess of 2 million barrels per day. The simulated mean value of 129 thousand barrels represents only 6.5% of this output rate. Another useful comparison is to the anticipated output rate from the rest of the USA when ANWR comes on line. If the EIA projections are accurate, we can expect US output to be below 6 million barrels per day by the year 2000. The simulated mean value of 129 thousand barrels from the ANWR represents roughly a 2% increase in total US output. The 95th percentile value of production in that year is 699 thousand barrels. Total production over 25 years averages 560

Table 3. Production profile assumptions.

Field size (billion barrels)

Peak production (%) First-year production (% of peak) Second-year production (% of peak) Decline rate (% per year)

Less than 0.5 OS-2

6.0 6.0

100 50

70 100 12 12

More than 2.0

5.4

40

100 12


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Figure 5. Annual production - DOI case.

Year

Figure 6. Annual production - EIA case.

oil resources in the Arctic National Wildlife Refuge

million barrels, with a maximum value of 9.65 billion and a 95th percentile value of 3.40 billion barrels. Of course there is a 70% probability of no production at all. Clearly, there is some potential for large volumes of production under the assumptions of this scenario, but the probabilities favour low output rates.

Simulation of EIA assumptions

The EIA procedure for projecting annual rates of oil output from the 1002 region was to accept DOIs distribution for oil in place and to assume that 25% of that amount would actually be recovered through exploration and development. Our simulation starts by sampling from the oil in place distribution. Total producible oil is then calculated as 25% of the sampled value for oil in place. This total is apportioned out to the appropriate number and size of fields, and each of these fields produces at the rates given in the tables above. Again, probability distributions for total production and annual production are produced by repeating the simulation 5 000 times.

The results for this case are shown in Figure 6, which shows the time profile for production. This figure shows the mean value for production each year, as well as the 5th and 95th percentiles of the production distribution. Production peaks in the fourth year after the first discovery is made, at a mean value of 409 thousand barrels per day. More striking is the wide range from the 5th to the 95th percentiles: over 600 thousand barrels per day in the fourth year. Thus even under the EIA assumptions there is a wide range of possible outcomes. However, those outcomes are distributed symmetrically about the mean, and the possibility of no output at all is remote. This is in marked contrast to the DO1 results (Figure 5), which show a high probability of no production and a small probability of large volumes of output. Total production for the EIA case over 25 years averages 1.69 billion barrels, roughly three times the DO1 average. However, the maximum value is only 4.82 billion, less than half the DO1 maximum. This is due to EIAs assumption of a 25% recovery factor. In the EIA model, even if there are 40 billion barrels in place, only one-quarter of that amount can be recovered. By contrast, the DO1 distribution for producible oil has a maximum of 20 billion barrels. Thus the distribution of total production for the EIA simulation is shaped quite differently from the DOI case: although the mean is higher, the upper tail does not extend to such high values.

A comparison of the simulations

Perhaps the easiest way to compare these two simulations is to examine the distributions for output in the year of maximum mean output (Figure 7). In the EIA simulation the mean output is 409 thousand barrels; in the DO1 case the mean is 129 thousand. Of course we would expect the DO1 case to be lower since it reflects a high geologic risk, while the EIA case has zero risk. But the contrast between the two cases is more dramatic than a comparison of the means shows. In the DO1 case there is a 70% chance of no oil being produced and only a 5% chance of more than 711 thousand barrels. In the EIA case, by contrast, there is essentially no chance of zero oil output, and a roughly 50% chance that output will exceed 392 thousand barrels. These results dramatize the fundamental differences between the modelling approaches taken by the two agencies. If we relied only on the DO1



1.0

1

0 EIA

Thousand barrels per day

Figure 7. Oil output in peak year.

report we would come away with a sense of the high risks of complete failure in the 1002 region. On the other hand, the EIA analysis would lead us to conclude that, while a considerable range of outcomes is possible, there is virtually no risk of complete failure. In the final section of this paper we will discuss the implications of these different approaches for public policy on the ANWR.

Sensitivity analysis

Our analysis to this point has concentrated on the differences between the studies carried out by DO1 and EIA, in particular on the widely differing views they project of the economic risks of ANWR development. In this section we utilize our model of oil exploration and production to further investigate the range of possible future outcomes. This analysis is designed to show how sensitive future oil output from the region is to key assumptions in the model. We will analyse two parameters in particular: the geologic risk in the DO1 formulation and the oil recovery factor in the EIA formulation.

As we have seen, the single most critical assumption made in the DO1 approach is the geologic risk, the probability that no oil at all is recoverable from the ANWR. In the base case reported above and in DOIs own assessment this risk was set at 70%. EIA argues, on the other hand, that the methods used by DO1 to determine geologic risk are too conservative, especially the assumption that if the five largest prospects are dry the whole area will be dry. EIA suggests that all 26 prospects should be included in assessing the area risk. If we do so the risk drops to 15%. We argued earlier that this was an extreme view of the probabilities involved, since it is equivalent to assuming that the prospect risks for all 26 prospects are independent. Thus rather than forming a balanced alternative to the DO1 assumption, we view this alternative as a lower bound on likely values of the geologic risk.

In order to test the sensitivity of the results to the geologic risk, we revised the DO1 simulation to include a geologic risk uniformly distributed between 50% and 70%. Recall that the risk is roughly 50% if ten prospects are included at a prospect risk of 93%. As expected, reducing the geologic risk increases production. In the fifth year, when maximum production is expected, the mean value is 170 thousand barrels per day. This compares to 130 thousand barrels in the base case. The probability that no oil will be produced falls from 70% to 55%. The 95th percentile of the conditional distribution for production changes very little: from 699 thousand barrels to 794. Thus we can conclude that a relatively large change in the geologic risk has a relatively small impact on estimated oil production.

For a similar sensitivity test of the EIA assumptions, we allowed the recovery factor to be uniformly distributed between 10% and 40%. This range brackets the 25% figure assumed in the EIA base case. The results again show a relatively modest change. In the fourth year, which is the year of maximum mean production for these assumptions, average production falls from 409 to 406 thousand barrels per day, while the 95th percentile value increases from 745 to 774 thousands barrels per day. Generally speaking, then, we can conclude that the overall results of the DO1 and EIA studies are not sensitive to the parameters chosen, but are sensitive to the fundamental structures of the models themselves.



Summary of results

The focus of this paper has been to attempt to reconcile the projections put forth by DO1 and EIA as to potential future oil production from the ANWR 1002 region. The DO1 study, while acknowledging the significant potential of the region, shows a very high probability that no oil at all can be economically recovered. However, if exploration and development are successful then we can expect a mean output value around 3.2 billion barrels, with a wide variance around this mean. The EIA study presents the economic risks of exploration in the 1002 region in a quite different light. By rejecting the DO1 argument for a substantial geologic risk and focusing on an average oil recovery factor the EIA study leads to the conclusion that not only is there likely to be large amounts of oil in the region but the risks of being able to produce only a small amount of it are negligible. Thus EIAs projection of recoverable oil of 3.4 billion barrels means something quite different from DOIs estimate of 3.2 billion, because the latter has only a one in five chance of occurring.

Our model allows us to bring these two approaches together and to develop a compatible set of projections of oil output over time. In doing this we essentially adopted the assumptions of the EIA study as to the number and sizes of fields which would be discovered for any volume of recoverable oil, and the subsequent production rates for these fields. Depending on the assumptions used, our results show production peaking four or five years after the start of development, at a mean rate that ranges from 129 to 409 thousand barrels per day. But these mean values are dominated by the wide ranges of uncertainty, even when using a single set of assumptions. This uncertainty is the fundamental fact influencing development strategy in the ANWR region, and neither DO1 nor EIA suggests a coherent method for choosing a socially optimal development plan in the light of this uncertainty.

Issues for future research

A number of important issues are raised by the question of how best to develop the ANWR 1002 region. The research we have reported here aims to clarify some of the underlying uncertainty about the geologic and economic potential of the region. However, it does not attempt to answer the difficult policy questions. It may serve, however, as a stepping stone to further analysis of these issues. Three issues particularly deserve further study:

0 modelling the exploration, development and production process; 0 determining the value of information on oil potential; and 0 determining the option value, or value to delaying leasing, in the

ANWR.

I will comment briefly on each of these. We have pointed out that the models developed by DO1 and EIA, as

well as the one presented here, are highly stylized models of the actual oil development process. These models ignore two issues that are vital to ANWR development. One is that the geographical locus of development within the ANWR is important to the environmental impact of development. The other is that the actual development process will involve a sequence of exploration and development decisions, each one



of which will be based on the knowledge acquired to that point. Both of these issues can only be analysed within a more disaggregated and realistic model of the development process.

A second important issue is the value of gathering information on the geologic potential of the region. In the DO1 report one of the alternatives considered (but rejected) by the Secretary was an information gathering campaign involving selective drilling of test wells. This alternative is particularly intriguing because much of the uncertainty surrounding the 1002 region could apparently be resolved with the drilling of one or two wells, which is all it would take to test whether the Ellesmerian sequence of sediments which provide the source of the Prudhoe Bay field are present in the 1002. As we have noted, fully half the potential of the 1002 is based on the presence of this play. If it were absent the entire region would be substantially downgraded in value. Thus an analytic treatment of the value of information and the design of a sequential development strategy would be valuable.

Finally, the possible option value of the ANWR, or the value of delaying an irreversible leasing decision, should be investigated. Even granting that a large quantity of oil exists in the region, it does not follow that the socially optimal time to produce that oil is as soon as possible. The federal agencies appear to assume just that, on the grounds that domestic production will be declining rapidly in the early decades of the next century, and the oil from the 1002 will be vital to reduce dependence on imports. But if it is vital to reduce dependence on imports when the USA is importing 65% of its oil, it may be more vital when it is importing 99%. Thus the question arises as to the optimal timing of ANWR development, given increasing US dependence on imports. A policy of delaying leasing (possibly linked with an informa- tional drilling campaign) also has the benefit of delaying and perhaps avoiding altogether the environmental costs of development.


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