U.S. Geological Survey Open-File Report 03-044
Version 1.0

Economics of Undiscovered Oil in the Federal Lands of the National Petroleum Reserve, Alaska

By Emil D. Attanasi

CONTENTS

Summary
Introduction
Summary of Geologic Assessment 
     Geologic Assessment Procedures
     Characteristics of the Assessed Technically Recoverable Resources
Data, Assumptions, and Procedure for the Economic Analysis 
     Data  
     General Assumptions and Scope of the Analysis
     Economic Assumptions
Procedures and Economic Analysis
     Transportation, Infrastructure, and Location Assumptions  
     Exploration and Field Development Costs
          Exploration Costs
          Field Development Costs
     Economic Rationale for Computations
Incremental Costs: Results and Interpretations
Conclusions and Limitations
References
Appendix A. Documentation of Costs 
     Product Transportation System
     Product Transportation Costs
     Field Development Costs
          Field Design 
          Development Drilling and Completion Costs 
          Facilities Costs
          Field Production Profiles
          Operating Costs
Appendix B. Tax and Royalty Rate Assumptions

ILLUSTRATIONS

(Each figure is a separate HTML file.)

Figure 1. Location of the National Petroleum Reserve Alaska in Northern Alaska
Figure 2. Frequency-size distribution of undiscovered conventional oil accumulations  associated with the mean, the 95^th and the 5^th fractile estimates of  the assessed oil in the Federal part of the National Petroleum Reserve Alaska Study Area.
Figure 3.  Frequency-size distribution of undiscovered conventional gas accumulations associated with the mean, the 95^th and the 5^th fractile estimates of the assessed oil in the Federal part of the National Petroleum Reserve Alaska study area.
Figure 4. Economic sub-areas of the Federal part of the National Petroleum Reserve Alaska study area.
Figure 5. Incremental costs in 2001 dollars per barrel for finding, developing, producing, and transporting oil from undiscovered oil accumulations in the Federal part of the National Petroleum Reserve Alaska study area.  
Figure A-1. Pipeline investment costs for the regional pipeline as a function of distance.
Figure A-2. Percentage of water in the oil production stream as a function of reservoir depletion for Alpine-type pools.
Figure A-3. Percentage of water in the oil production stream as a function of reservoir depletion for Kuparuk-type pools.
Figure A-4. Annual operating costs are a function of the design average daily fluid production.

TABLES

(Tables 1-4 are at the end of this HTML page; tables A-1 - A-5 are at the end of the appendix file.)

Table 1. Mean value of undiscovered technically recoverable conventional oil, natural gas, and natural gas liquids by play in the Federal part of the National Petroleum Reserve Alaska
Table 2. Cumulative percentage distribution of the technically recoverable oil in the Federal portion of the NPRA study area by oil field size class
Table 3. Assessed mean technically recoverable oil, associated gas, and natural gas liquids in undiscovered oil accumulations in the Federal portion of the National Petroleum Reserve Alaska study area distributed by economic sub-area
Table 4. Incremental costs of finding, developing, producing, and transporting oil and natural gas liquids from undiscovered oil accumulations in the Federal part of the National Petroleum Reserve Alaska study area
Table A-1. Distances assumed for transport of crude oil to the Trans-Alaska Pipeline System
Table A-2. Estimated transport costs in dollars per barrel used in the economic evaluations from accumulation to the Trans-Alaska Pipeline System
Table A-3. Selected characteristics of reservoir attributes of the Beaufortian Upper Jurassic oil plays of the National Petroleum Reserve Alaska
Table A-4. Estimates of facilities investment costs in 1996 dollars per barrel of field reserves
Table A-5. Accumulation production profiles assumed for new discoveries in the National Petroleum Reserve Alaska

TABLE OF CONVERSION TO SI UNITS  

        barrel                                           0.159                                         cubic meter
      cubic foot                                     0.02832                                     cubic meter
         foot                                             0.3048                                       meter  

UNIT ABBREVIATIONS

BBO … Billions of barrels of oil
BBL … Billions of barrels
TCF … Trillions of cubic feet
MMBO … Millions of barrels of oil
BCF … Billions of cubic feet
bbl … barrel

SUMMARY

     This report summarizes the economic analysis of the U.S. Geological Survey’s 2002 petroleum assessment of the Federal lands in the National Petroleum Reserve Alaska (NPRA) study area. In addition to Federal lands, the study area included Native Lands within NPRA and areas underlying Alaska State waters.  Estimates of technically recoverable oil in undiscovered oil accumulations in the Federal area of NPRA range from 5.9 billion barrels of oil (BBO) to 13.2 BBO, with a mean of 9.3 BBO.  The ranges in estimated volumes correspond to the 95 percent probability (that is, a 19 in 20 chance the actual volume will exceed that 95^th fractile volume) and the 5 percent probability level (1 in 20 chance the actual will exceed 5^th fractile volume), respectively.  Estimates of technically recoverable non-associated gas in undiscovered gas accumulations range from 39.1 (95^th fractile) to 83.2 (5^th fractile) trillion cubic feet of gas (TCF) with a mean value of 59.7 TCF.  Non-associated gas resources were not evaluated in the economic analysis because a market for newly discovered North Slope gas remains to be developed.

     Characteristics of the assessment that are important for the economic analysis included the petroleum accumulation size-frequency distribution, location, and depth. At the mean estimate, 0.6 BBO is in accumulations of at least 500 million barrels. Accumulation size-frequency distributions associated with the 95^th and 5^th  fractiles indicate 0.2 BBO and 1.2 BBO were assessed in accumulations of at least 500 million barrels, respectively. At the mean quantity of oil assessed, only 37 percent of the oil was assigned to accumulations of at least 250 millions barrels in size. The Federal part of the study area accounted for 88 percent of the technically recoverable oil assessed and 97 percent of the gas assessed in gas accumulations

     Results of the economic analysis are presented as separate cost functions associated with the mean, 95^th, and 5^th fractile estimates of undiscovered technically recoverable oil.  An after-tax 12 percent rate of return or hurdle rate was assumed.  All calculations are in constant 2001 dollars. Transportation costs from the field to the market were included in the analysis so that prices and incremental costs are at the market rather than at the wellhead.  Incremental cost functions include the full costs of finding, developing, producing, and transporting oil to market.

     At a $21 per barrel market price, 0.4 BBO associated with the mean estimate and 2.2 BBO associated with the 5^th fractile estimate are economic to find, develop, produce, and transport to market.  For resources associated with the 95^th fractile estimate, initial exploration costs are not compensated by the economic value of new finds until market prices reach at least $22.40 per barrel. At a market price of $25 per barrel, 27 percent of the technically recoverable oil assessed at the 95^th fractile (1.6 BBO), 39 percent of the oil assessed at the mean (3.7 BBO), and 47 percent of the oil assessed at the 5^th fractile (6.2 BBO) is economic to find, develop, produce, and transport to market. 

INTRODUCTION

     The 2002 U.S. Geological Survey assessment of the National Petroleum Reserve-Alaska (NPRA, Figure 1) posits a set of scientifically based estimates of undiscovered in-place and technically recoverable quantities of oil and gas in accumulations that can be produced with conventional recovery technology. The study area included that part of the NPRA owned by the Federal government, lands underlying adjacent Alaska state waters, and native lands within the NPRA borders.  Geologists assessed volumes of recoverable oil and gas that could be added to proved reserves using current technology but without reference to costs or product prices.  The costs and the product prices required to transform the assessed undiscovered technically recoverable resources into producible reserves are estimated in this report.

     This analysis determines that part of the assessed distribution of undiscovered accumulations that can be commercially developed at particular market prices. The analysis also estimates the incremental costs of finding, developing, producing, and transporting to market the assessed undiscovered oil.  Incremental cost functions show cost-resource recovery possibilities and are not supply functions as strictly defined by economists.  However, the incremental cost functions and the data that underlie the functions are often used in market supply models.  The economic analysis is confined to resources in the Federal portion of the NPRA study area.  This analysis does not predict the revenue or bonus payments for leases in the NPRA nor does it attempt to estimate regional or national secondary economic benefits that may result as a consequence to development of the resource. 

     The economic component of the NPRA assessment is intended to place the geologic resource analysis into an economic context that is informative and easily understood by government policy makers and industry decision makers.  The geologic assessment might best be described as a regional reconnaissance appraisal. The geologists attached subjective regional occurrence probabilities to hydrocarbon accumulations to capture play and prospect risk. They also formulated subjective probability distributions for reservoir attributes of such accumulations, using data from a limited number of available field studies, regional geophysical studies, knowledge about regional trends, and the postulated regional geologic history.  The reservoir attribute distributions are used to predict size, depth, and production characteristics of undiscovered accumulations. 

     The scope of the economic analysis is also general rather than site or prospect specific. The economic analysis is limited to the evaluation of general finding costs, development costs (including the costs of primary recovery and some aspects of secondary recovery), and the costs of transporting the product to market.

     Undiscovered technically recoverable conventional oil and gas resources are resources that are estimated to exist, on the basis of broad geologic knowledge and theory, in undiscovered accumulations outside of known fields.  Technically recoverable resources are producible using recovery technology that is currently available but without reference to economic viability.  Conventional oil and gas accumulations are discrete well-defined accumulations, typically bounded by a water contact, from which oil, gas, and natural gas liquids (NGL) can be extracted using traditional development and production practices.  Accumulations assessed by geologists outside of known fields were considered for the purposes of the economic analysis as separate and discrete new fields.   Economically recoverable resources are that part of the assessed technically recoverable resource for which the costs of finding, development, and production, including a return on capital, can be recovered by production revenues at a particular price.

     The discussion first briefly reviews the geologic assessment procedures. It then summarizes characteristics of the technically recoverable resources important for understanding the economic analysis.  Assumptions about markets, pricing, costs, and the technical relationships used in computing the incremental cost functions are considered.  Finally, results and interpretations of the economic analysis are presented in the concluding section.

Summary of Geologic Assessment

     The geologic assessment method and results are only briefly reviewed here; detail is provided in Schuenemeyer (2002, unpublished data).  The commercial value of a newly discovered oil and gas field depends on its expected size, hydrocarbon type (oil or gas [1] ), depth, location, and reservoir attributes. These properties and the probability distributions used to characterize them are fundamental to understanding the results of the economic analysis.

Geologic Assessment Procedures

      The geologic assessment used a play analysis paradigm.  According to this paradigm (Baker and others, 1984), a play is a set of known or postulated oil and (or) gas accumulations sharing similar geologic, geographic, and temporal properties, such as source rock, migration patterns, timing, trapping mechanism, and hydrocarbon type.  Individual geologists were assigned known rock units within the Study Area.  Based on geologic knowledge and results of exploration throughout Northern Alaska, each geologist defined, delineated, and described the petroleum plays that were to be assessed.  For each play, the assessment geologist assigned subjective probabilities to describe the play and prospect risks.  They also assigned subjective probability distributions to characterize attributes of undiscovered conventional oil and gas accumulations. The minimum values of the attributes were calibrated so the smallest size of the assessed accumulations was 50 million barrels (MMBO) of oil in-place or 250 billion cubic feet of gas (BCF) recoverable.

    The geologic risk structure is modeled by assigning a play probability to each play. This probability is the likelihood that at least one accumulation of the minimum size (50 MMBO in-pace or 250 BCF gas recoverable) occurs. In cases where the assessor was not confident of the occurrence of at least one accumulation of that threshold size, the play probability was computed as the product of the occurrence probabilities of the three play attributes of charge, trap, and timing.  The geologist also assigned a prospect probability to each play that represented the probability that any randomly chosen prospect is an accumulation at least as large as the minimum size.  This probability may be computed as the product of the occurrence probabilities assigned by the geologist to the prospect attributes of charge, trap, and timing.  The number of accumulations (meeting the threshold size) is then the product of the number of prospects, the play probability, and the prospect probabilities. Numbers of prospects were simulated for each play realization by sampling from the subjective probability distribution specified by the assessment geologist.

     Data on reservoir attributes for plays were gathered from discoveries outside of NPRA and from analogue plays occurring elsewhere on the North Slope.  Subjective reservoir attribute [2] probability distributions were elicited from the geologists. The resulting reservoir model was then applied to generate the potential sizes of undiscovered accumulations. In particular, the assessors specified subjective probability distributions for the following reservoir attributes (1) net reservoir thickness, (2) area of closure, (3) porosity, and (4) trapfill.  The subjective distribution for each attribute was determined by the geologist’s choice of distribution shape, the distribution’s minimum value (lower truncation point), the maximum value, median (50^th fractile) value, and the value assigned to the upper 5^th fractile [3] .  Each assessor-specified distribution was fit to a beta or modified beta distribution that was later used as a basis for numerical simulation.  The assessment geologists also formulated subjective probability distributions to characterize the number of prospects and depths of accumulations. Beta distributions were also used to describe these distributions.

     In total, the assessment geologists evaluated 24 petroleum plays within NPRA and lands underlying adjacent State waters.  The play descriptions with their geographic locations and geologic characteristics are summarized in Bird (2002).  Most of the plays thought to occur in the study area also occur elsewhere in Northern Alaska.  Supporting studies were prepared by the geologists and by other assessment team members to assist in characterizing play properties with probability distributions (see Kumar and others, 2002;Verma and Bird, 2002).  New information included digitally reprocessed seismic data and other new geo-chemical data, and data from new discoveries near the NRPA, and data from new discoveries outside of the NPRA in plays that occur in the NPRA.  

     Probability distributions describing the sizes of accumulations and numbers of accumulations and volumes of hydrocarbons for individual plays were calculated by the following simulation scheme.  For each replication, i, i=1,…,N,  the play risk was evaluated. For each successful play, a variate for the risked number of accumulations in the play was computed as the product of the prospect probabilities and a random draw from the assessor’s (subjective) distribution describing the number of prospects.  For each realization of the play represented by the n_i accumulations, the probability distributions representing the reservoir attributes were sampled n_i times, thus providing a size for each accumulation (footnote 2).  Ten thousand replications defined the probability distributions describing each successful play.

     Pair wise dependencies of the characteristics of charge, trap, and timing were assigned between plays within the study area.  The ranked dependencies (high, medium, low) were transformed into a measure of covariance between plays. Because the play assessment results are characterized by probability distributions, the covariance among plays was assessed in order to aggregate play results to higher levels (that is from the Federal to the entire study area).  Aggregation procedures for the play probability distributions are provided in detail in Schuenemeyer (2002, unpublished data).

Characteristics of the Assessed Technically Recoverable Resources

      Estimates of technically recoverable oil in undiscovered accumulations in the Federal part of the NPRA range from 5.9 BBO to 13.2 BBO with a mean of 9.3 BBO. The ranges in estimated volumes correspond to the 95 percent probability (that is, a 19 in 20 chance of occurrence) and the 5 percent probability level (1 in 20 chance), respectively.   The Federal portion had been assigned about 88 percent of the oil in the study area. [4]   The estimates of technically recoverable non-associated gas in undiscovered gas accumulations in the Federal area ranged from 39.1 TCF to 83.2 TCF with a mean of 59.7 TCF.  About 97 percent of the assessed gas in gas fields in the entire study area had been assigned to Federal areas.   Table 1 presents play level and total mean estimates of oil, associated gas, associated gas NGL, non-associated gas, and non-associated NGL for the Federal area. Two plays (the Beaufortian Upper Jurassic Topset Northeast and the Beufortian Upper Jurassic Topset Northwest; Table 1) account for two-thirds of total oil assessed in the Federal area. Almost half of the total gas assessed in gas accumulations in the Federal Area was assessed in the two plays (the Brookian Topset Structural Play and the Torok Structural play; Table 1).

     The depths assigned by the assessors to gas accumulations (Schuenemeyer, 2002, unpublished data) and engineering predictions of natural gas liquids (NGL) to gas ratios for gas accumulations (Verma and Bird, 2002), implied that the likelihood would be negligible that a single large gas accumulation would have a ratio sufficiently high for the field to be developed for its liquids.  Technically recoverable oil accumulation size-frequency distributions (shown in Figure 2) convey some of the economic implications of the oil estimates.  Few small accumulations are shown because accumulations having oil in-place of less than 50 million barrels were not considered in the assessment.

     Based on the size-frequency distribution (Figure 2) associated with the mean estimate of undiscovered technically recoverable oil, only 0.6 BBO (6.8 percent) of the assessed oil is assigned to accumulations of at least 500 million barrels (see Table 2).  Similarly, accumulations of at least 500 MMBO account for 0.2 BBO (4 percent) and 1.2 BBO (9 percent) of the oil shown by the distributions for the 95th and 5th fractile estimates, respectively.  Table 2 shows that accumulations larger than 256 MMBO account for 3.5 BBO (37 percent), 1.8 BBO (32 percent), and 5.9 BBO (44 percent) of the oil associated with the mean, 95th, and 5th fractile estimates, respectively.  The assessed volumes of oil are significant, but only a limited part was assigned to accumulation sizes of current economic interest.

     Assessment results that are summarized in Bird and Houseknecht (2002) show that most of the oil at the play level is expected to be concentrated in plays geographically confined to the northern part of NPRA.  The four plays with the largest volume of oil (Beaufortian Upper Jurassic Topset Northeast, the Beaufortian Upper Jurassic Topset Northwest, Brookian Clinoform North and Brookian Clinoform Central; Table 1), at the mean estimate account for 8.1 BBO or 88 percent of the total oil. Overall, 7.7 BBO or almost 83 percent oil estimated at the mean was assigned to accumulations having depths between 5,000 and 10,000 feet, and only 0.4 BBO or 4.4 percent was assigned to depths of less than 5,000 ft.  No oil accumulations were assigned at depths greater than 15,000 feet.

     Figure 3 shows the size frequency distribution of the assessed undiscovered gas accumulations. The magnitude of the total assessed gas in gas accumulations is large. At the mean estimates, however, about one third of the gas was assigned to accumulations of at least 1.5 TCF in size. Accumulations between 770 BCF and 1540 BCF in size were assigned about 27 percent of the total gas assessed.  Although large volumes of gas in Northern Alaska currently have no commercial markets, the assessed magnitude and frequency- size distribution of the accumulations may be useful to those planning a future gas transportation system. The size distributions show the largest part of the assessed resources in moderate size accumulations. 

            The majority of the gas resources in gas accumulations are assigned to the southern and western part of NPRA.  In the Federal part of the study area, the four plays with the largest volume of non-associated gas resources (the Brookian Topset Structural, the Torok Structural, the Beaufortian Clinoform, and the Brookian Clinoform Central plays; Table 1) – account for nearly two-thirds of the non-associated gas.  About 43 percent of the assessed non-associated gas was assigned to depths between 10,000 and 15,000 feet and 19 percent was assigned to depths greater than 15,000 feet.      

     The assessors were also required to describe the expected quality of the resource, in terms of the oil gravity and contaminants of oil and gas. The average gravity for the assessed oil was about 38 degrees API. The gravity of the assessed oil is somewhat lighter than oil found near Prudhoe Bay area (Fig. 1) and those differences in oil gravity are attributed to differences in sources.    There was no indication that contaminants in the assessed oil would present special problems refining (for play assessment data see Schuenemeyer, 2002, unpublished data).

     The characteristics of the technically recoverable oil most important to the economic analysis are the volumes of oil, the oil accumulation-size distribution, depth of the oil, and geographical location of the resources.  Distributions in Figure 2 and supporting data (Table 2) show that most of the assessed oil was assigned to accumulations of modest size.

Data and Economic Assumptions

Data

      Data generated for the geologic assessment computer simulations included accumulation size (volume of recoverable oil, gas, and natural gas liquids), accumulation depth, accumulation area, net reservoir thickness, reservoir porosity, and the oil formation volume factor for oil accumulations and the gas compressibility factor, initial gas pressure, and reservoir temperature for gas accumulations.  These data were used to develop expected production well recoveries for various accumulation size classes at pre-specified depth intervals. The simulation data were also used to compute ratios of gas-to-oil and NGL-to-natural gas by 5,000-foot depth intervals.  

     Cost information was drawn from previous economic studies of the Northern Alaska (Broderick, written communication, 1992, Young and Hauser, 1986, National Petroleum Council 1981a, 1981b, Thomas and others, 1993, Thomas and others, 1991, Han-Padron Associates, 1985).  Additional data on recent cost trends were obtained from a variety of sources, including British Petroleum, (1996), Blount and others (1993), Broman and others (1992), Craig (2002), and written communication from the State of Alaska Pipeline Office (1998), and from J. Craig (Minerals Management Service, oral communication, 2002), and the technical literature.  Drilling cost data from the Annual Joint Association Surveys (JAS) (American Petroleum Institute, 1997, 1999, 2000, 2001) were used to formulate drilling cost estimates.  Engineering data (Arco-Alaska, Inc, and others, 1998; Thomas and others, 1993) were used to predict the water cut of produced oil as a function of pool depletion.

General Assumptions and Scope of Analysis

     The economic analysis presents estimates of the incremental costs of converting assessed undiscovered resources into additions to proved reserves.  Cost functions include the costs of finding, developing, producing, and transporting to market resources in currently undiscovered accumulations.  These functions are not the same as the economist’s market price-supply predictions because at any given price the oil and gas industry will allocate funds over a number of provinces and supply sources in order to meet market demand at lowest costs.

     An observed price-supply relationship represents the culmination of numerous supplier decisions over many projects and regions.  Incremental cost functions are computed independently of activities in other areas.  Furthermore, the incremental cost functions are assumed to be time independent and should not be confused with the firm supply functions that relate marginal cost to production per unit time.  Because of the time-independent nature of the incremental cost functions and the absence of market demand conditions in the analysis, user costs or the opportunity costs of future resource use are not computed.  However, the incremental cost functions and data that underlie the functions can be used in market supply models.

     Undiscovered non-associated gas fields were not evaluated here because a viable gas transportation system does not exist in Northern Alaska, nor are the conditions yet established that would permit gas that is distant from the Prudhoe Bay gas conditioning plant to enter any proposed pipeline to market.  Commercial gas will affect economic valuation of oil in two ways.  The commercial sale of by-product gas enhances the economic worth of developing and producing a newly discovered oil accumulation.  Also, gas exploration, when targeted in oil prone areas, typically accelerates the evaluation process for oil by generating information useful to those searching for oil. At this time, however, these effects on NPRA oil valuation are probably limited for the following reasons.  First, the largest part of the assessed oil and gas resources in the NPRA were assigned to different geographic areas.  Secondly, any positive value assigned to associated gas should incorporate the element of time for gas investment payback.  The future date of the gas market development is still uncertain.  Moreover, when such a market develops, the limited gas pipeline capacity available to producers outside of the Prudhoe Bay area will likely be reserved for new discoveries of gas in gas accumulations.  This drives any expected commercial value of gas in oil fields (associated gas) in the NRPA to rather low levels.    

     In Northern Alaska, 30 TCF of associated gas has already been discovered.  It can be produced cheaply if a gas market develops.  However, the US Energy Department forecast for 2020 projected that no Alaskan natural gas would be transported to the conterminous United States (Energy Information Administration, 2001).  Now, associated gas produced with oil is typically stripped of its liquids and re-injected into the oil field or used as fuel on the lease.  Some of the recovered natural gas liquids are now mixed with crude oil and transported through the Trans-Alaska Pipeline System (TAPS) and some are re-injected as a miscible fluid flood for enhanced oil recovery. This analysis assumed that associated gas is re-injected into the reservoir or used as lease fuel.

Economic Assumptions

     Economic models are abstractions that characterize real economic systems, and the models are typically just detailed enough to roughly approximate the outcomes of interactions between economic agents.  Only the general direction and the approximate magnitude of the reaction of the system to price or cost change can be modeled.  For most models, it was assumed that the industry will not make an investment unless there is the expectation that the full operating costs, capital, and cost of capital will be recovered.  For this study, it was assumed that decision makers know the values of physical and economic variables with certainty.  It was also assumed that areas considered in the economic analysis were available to exploration for oil.

     Costs used in this analysis were assumed to represent those prevailing in January of 2001.  Calculations were in terms of constant real dollars. The discounted cash flow (DCF) analysis was specific to individual projects and ignored minimum income taxes and tax preference items that might be important from a corporate accounting stance. A 12 percent after-tax required rate of return was assumed.  Federal income tax provisions included the changes made in 1993.  Based on the 1986 Tax Reform Act, 30 percent of development well drilling cost is classified as tangible cost and is therefore capitalized over 7 years.  Of the remaining 70 percent of drilling cost (that is, the intangible drilling cost), 30 percent is depreciated over 5 years and the remaining 70 percent is expensed immediately.

     Alaska state taxes include the severance tax, income tax, and ad valorem tax.  The severance tax depends on field and well productivity (see Appendix B for details).  Although the nominal state income tax rate is 9 percent, the effective tax rate is set by a complex formula based on the specific firm’s production and sales.  For planning purposes, State agencies use a rate of 1.4 to 3.0 percent of net income.  An effective tax rate of 2.4 percent is used here.  Alaska’s ad valorem tax is an annual charge equivalent to 2 percent of the economic value of equipment, facilities, and pipelines.  The Federal corporate tax rate used in the project analysis was 35 percent.  The extreme Northeastern area of the NPRA was identified as a high potential area by the Bureau of Land Management (BLM), (Bureau of Land Management, 1998), and this area required a one-sixth royalty payment on resources developed. Elsewhere in the NPRA, a one-eighth Federal royalty was assumed.

     During the last thirty-five years, nominal oil prices in the conterminous United States have varied over a range from $3 to $40 per barrel.  Discussion in this report focuses on reserve additions from new fields that might be expected with an oil price range of $18 to $30 per barrel in 2001 dollars.  The oil price discussed is the landed US West Coast price rather than the well-head price.  In the absence of gas markets, the well-head price of gas was assumed to be zero.  The well-head price of natural gas liquids was assumed to be 75 percent of the per barrel price of crude oil.  Although graphs may show additions to reserves for higher prices, it would unrealistic to assume that constant real costs would hold if real oil prices rise to $40 per barrel.  Experience has shown that oil and gas price increases lead to escalation in industry capital and operating costs (Kuuskraa and others, 1987).

Procedures for the Economic Analysis

Transportation, Infrastructure and Location Assumptions

     Oil produced in Northern Alaska is shipped via the Trans-Alaska Pipeline System (TAPS) to southern Alaska for ocean tanker transport to market. The nominal capacity of the TAPS is 2.1 million barrels per day.  In 1988, TAPS transported an average of 2.0 million barrels per day of oil.  For 2001, just less than 1 million barrels per day of oil and natural gas liquids were transported, so that even now there is perhaps a million barrels per day of unused capacity.

     The Alpine field (Figure 1) and its satellite discoveries are located near the northeast edge of the NPRA. The crude oil produced at Alpine is transported in a small pipeline to the Kuparuk River field (adjacent to the Prudhoe Bay field) where it is, in turn, transported to the Trans-Alaska Pipeline System’s Pump Station 1.  Alpine and its satellite discoveries are expected to fully utilize the small pipeline from the edge of NPRA to the Kuparuk River field for the next decade, so it will not be immediately available for transporting oil from new NPRA discoveries.  For new oil discoveries in northern NPRA, it was assumed that a 24-inch regional pipeline would be built from the interior of NPRA to the Kuparuk River field, the oil would be transported to TAPS Pump Station 1, located within the Prudhoe Bay field (Figure 4). 

     For the purpose of estimating likely product transport costs, the NPRA was partitioned into eight sub areas (Figure 4). Geologists were asked to allocate assessed oil and non-associated gas resources to these subareas.   New discoveries within each sub area are assumed to have similar transportation costs. Table 3 shows the subarea allocations of the mean estimates of oil in oil accumulations and gas in gas accumulations. At the mean estimate, 85% of the assessed oil in oil accumulations was assigned to subareas 110, 120, and 130; with two-thirds of the total oil assigned to sub-areas 110 and 120.  With almost all of the oil concentrated in the northern set of sub-areas, it was assumed that a 24 inch diameter regional pipeline would be built in stages and would roughly bisect the north/south width of the prospective area of sub-areas 110, 120, and 130.  For oil assigned to subareas 210, 220, and 230, the transportation cost computations assumed that a smaller diameter (20 inch) regional pipeline would be built that would roughly bisect those areas (north of the foothills) to carry oil directly eastward to TAPS Pump Station 2 (Figure 4). 

     Distances from the designated centroid points within the sub-areas were used for estimating pipeline materials and construction investment cost.  A regulated common carrier pipeline business entity is assumed to build and operate the regional pipelines to the TAPS.  Pipeline tariff charges were set to meet all operating costs and taxes, and to assure investors a 12 percent after-tax return on investment.  The liquid flow capacity for the 24 inch diameter pipeline was assumed to be at least 500,000 barrels per day (Han-Padron Associates, 1987) and the capacity for the 20 inch pipeline was assumed to be 300,000 barrels per day (Han-Padron Associates, 1987).  Pipeline investment cost functions originally presented in Young and Hauser (1986), and later updated by Broderick (written communication, 1992), were further adjusted to reflect the continuing decline in pipeline costs experienced on the Northern Alaska.  Estimates of costs considered typical of the Prudhoe Bay area were inflated by 30 percent to account for the remoteness and special rules for the NPRA. Distances that were assumed are provided in Appendix A. 

     Other than the rough allocations made by the geologists to the sub-areas in Figure 4, there was no spatial dimension to the assessment.  Unless the assessment geologist provided other information, accumulations were assumed uniformly distributed within the prospective area of each block.  Given that assumption, the average cost to transport the oil to TAPS is calculated in two stages.  First, it was assumed that 12 inch or 16 inch lateral pipelines were built from the border of the accumulation to the regional pipeline, and that the oil is transported eastward by regional pipeline system.  The regional pipeline from Northern NPRA, was assumed to use the Kuparuk field pipeline system for transport to Pump Station 1 where an additional tariff of $0.21 per barrel was charged for transport to TAPS.  The parallel regional pipeline from the sub-areas 210, 220, and 230 was assumed connected to TAPs Pump Station 2 (see figure 4).

     The TAPS tariff rate and marine transport rate to market are projected semi-annually by the Alaska Department of Revenue.  The marine transport rate represents the cost weighted by projected sales volumes of transporting crude oil from the Port of Valdez in Southern Alaska to a set of destinations the include the US lower 48 West Coast, the Far East, and the US mid-continent region.  These rates are projected on an annual basis to 2020 in nominal dollars (Alaska Department of Revenue, 2001). Assuming a 3 percent inflation rate, in constant real 2001 dollars, the average projected TAPS tariff for the period is $2.88 per barrel and similarly, the marine transport cost is $1.43 per barrel for a total rate of $4.21 per barrel.

Exploration and Field Development Costs

      Exploration and field development methods in the Northern Alaska differ from those of the lower 48 States.  Wildcat drilling occurs in winter when temporary ice roads, ice pads, and ice airstrips are constructed to support drilling activities.  Seasonal instability of the permafrost requires construction of gravel pads to support permanent production wells and facilities.  Production wells are drilled directionally from the pads to target distant locations at depth.  Gravel drilling pads can typically support as many as 40 well collars spaced at 10 foot intervals along with production equipment.  Sidetrack and multilateral drilling of two or more wells using a single well collar enables the maximum utilization of individual drilling pads.  The remoteness of the targets, the climate, and the absence of infrastructure impose high initial exploration and development costs on prospects.

     For a stand-alone field development, produced oil is processed at the field’s central processing facility and then transported from the periphery of the field to the TAPS.  Because commercial accumulations are large and they provide a substantial payoff in terms of the volumes of oil that incremental increases in recovery can yield, operators try to introduce technological innovations quickly.  For example, the application of extended reach drilling has allowed access to distant reaches of the reservoir, sometimes allowing satellite field development from existing drill pads.  For this study, it was assumed that any offshore accumulations within the NPRA that occur beneath the lagoonal areas between the shoreline and barrier islands can be developed from onshore drilling pads.

     The costs estimated in this study are generic and they only account in a very general way for the remoteness and the special regulations (such as the prohibition of permanent haul roads imposed on operations in the NPRA).  Baseline costs were generally calibrated for Prudhoe Bay area operations and increased by 30 percent to account for the higher costs of operation in the NPRA.  Cost estimates are quite uncertain but this broad range of uncertainty will undoubtedly narrow as industry gains experience in developing resources in the NPRA.

Exploration Costs

     Exploration effort leading to new field discoveries is represented by the drilling of wildcat wells.  Exploration costs are accounted for after the lease is acquired.  Non-drilling exploration expenditures (exclusive of lease bonuses) were assumed to amount to no more than 50 percent of the drilling cost (Energy and Environmental Analysis, Inc., 1993). Non-drilling exploration expenditures include geologic and geophysical data collection after lease acquisition, scouting costs, and overhead charges associated with land acquisition. Wildcat well drilling costs were assumed to be twice the cost of drilling production wells in the NPRA. [5]     New field exploration was evaluated in increments of 20 wildcat wells and a minimum cost of 10 million dollars per well was assumed for the first twenty wildcat wells drilled.   Actual exploration costs, however, will depend on site-specific characteristics of each prospect.  For this study, generic costs were used because play analysis does not provide specific locations.

Field Development Costs

     The continuing reduction in capital and operating costs for new discoveries on the Northern Alaska has been substantial (Williams, 2001a, 2001b, 2001c, Thomas and others, 1993, Harris, 1987a, 1987b).  The two principal field development costs categories are facilities costs and well costs (drilling and completion of production and injection wells).   Design and cost data are presented in Appendix A.

     Field drilling costs were based on the number of wells required to develop fields and the cost per well.  Per well drilling cost estimates were assumed to represent long-run future costs, and they were estimated using data from the Joint Association Survey (American Petroleum Institute, 1998-2001).  The estimated Prudhoe Bay area drilling costs were increased by 30 percent to compensate for a lack of infrastructure and(or) special regulations associated with the NPRA.  Estimated drilling and completion costs per conventional development well were as follows: (1) $2.5 million for depths to 5,000 feet, (2) $3.2 million for 5,000 feet to 10,000 feet depths, and (3) $5.1 million for 10,000 feet to 15,000 feet depth.   No oil was assessed at depths greater than 15,000 feet. In the northern NPRA economic sub-areas, nearly all of the assessed oil is from the Upper Jurassic Beaufortian Play, Northeast and Northwest (Table 1).  It was assumed that fields in these areas are developed with horizontal wells.  Appendix A provides more detail on the drilling cost analysis.    

     The number of wells required to develop a discovery depends on well productivity.  Expected values for well productivity were calculated using the play level reservoir attribute values associated with each simulated accumulation.  For each accumulation size and depth category, average well productivity based on an assumed production well spacing was calculated as the weighted average of the well productivity of the predicted accumulations occurring in that classification.  Well productivity estimates varied substantially across different depth intervals and within the same accumulation-size category, reflecting broad variations in reservoir quality of the plays occurring in the depth interval.  Conventional production wells were assumed drilled on 160 acre spacing and horizontal production wells on 320 acre spacing.  For each conventional production well, it was assumed that 0.4 injection wells (water or gas) would also be drilled (National Petroleum Council, 1981a, Young and Hauser, 1986) and for horizontal wells one injector would be drilled for each production well.

     Facilities include drill pads, flow lines from drilling sites, a central processing unit, and infrastructure required for workers.  Facilities design and costs depend on peak fluid flow rates and ultimately on the field size.  This cost category has had the most dramatic reduction during the last decade, as operators have introduced new field designs and systems in an effort to minimize costs.  The application of technology that resulted in extended reach drilling and multilateral production wells has reduced the number and size of drill pads needed for field development (Williams, 2001a). Facilities investment cost levels calibrated for the Prudhoe Bay area were increased by 30 percent to compensate for the special provisions attached to field development in the NPRA.

     Development of new discoveries on a satellite or facilities cost-sharing basis can reduce facilities costs and reduce the time to production.  Without site-specific information, it would be difficult to defend a blanket assumption that all of the smaller accumulations that were assessed could be developed on a satellite basis. The nature of the geologic assessment is general and even the sub-areas to which the geologist made the allocations of the play resources are large.  Table 3 shows the allocations of oil accumulations and resources to the individual sub-areas.  Actual savings are site-specific because certain facilities costs such as drill pads, internal roads, and product transportation are location dependent. 

     It was assumed that facilities sharing could, on average, result in a 30 percent reduction in facilities investment costs (Thomas and others, 1993) for sub-areas 110 and 120.  In this type of facilities sharing arrangement, production from the smaller field is sent to the central processing unit of the larger field, with the liquids product then taken by a sales pipeline and the gas and water returned to the small field for injection [6] .  For this study, facilities-sharing was limited to accumulations smaller than 130 million barrels but larger than 30 million barrels in the 110 and 120 sub-areas only.  Facilities-sharing in other economic sub-areas is less likely because of the small numbers of assessed fields, the small volumes of undiscovered oil, and the probability of greater distances between fields.

     Field operating costs include labor, supervision, overhead and administration, communications, catering, supplies, consumables, well service and work-overs, facilities maintenance and insurance, and transportation.  Some costs, such as well work-over costs have declined because of the introduction of new materials such as coiled tubing (Williams, 2001a, 2001c, 2001d).   For this study, annual field operating costs were estimated as a function of hydrocarbon and water fluid volumes (Appendix A).  These volumes were projected annually using field production forecasts and water cut functions based on historical data from the Kuparuk reservoir (Thomas and others, 1991) and the projected water cut/oil depletion for the Alpine reservoir (Arco Alaska, Inc, and others, 1998). The water cut increases as the reservoir is depleted, thereby increasing the per barrel cost of oil.

Economic Rationale for Computations

     Accumulation size, depth, regional costs, and co-product ratios determine whether a field will be commercially developable.  A new accumulation is commercially developable if the after-tax net present value of its development is greater than zero. For this study, the algorithm that calculated incremental costs used the predicted size and depth distribution of undiscovered fields (at the sub-area level) to compute quantities of resources that are commercially developable at various prices.  To compute finding costs, the geologic assessment is coupled with a finding rate model (Attanasi and Bird, 1996, Attanasi, 1999) to forecast the size and depth distribution of new discoveries from increments of wildcat drilling.  These forecasts drive the economic field development and production process model to determine the aggregate value of new discoveries and to determine the number of successive increments of wildcat wells that should be drilled.

     The commercial value of developing a representative field for a specific field size class (Figure 2) and depth category is determined by a discounted cash-flow (DCF) analysis at a given price.  The net after-tax cash flow consists of revenues from the production of oil less the operating costs, capital costs in the year incurred, and all taxes.  All new discoveries of a particular size and depth category are assumed developed if the representative field is found to be commercially developable (that is, if the after-tax DCF is greater than zero, where the discount rate of 12 percent represents the cost of capital and the industry's required return).  It is assumed that when operator income declines to the sum of the direct operating costs and the operator's production-related taxes, then the economic limit rate is reached and field production stops. 

     Newly discovered commercially developable fields are aggregated to provide an estimate of potential reserves from undiscovered fields for a given price and a required rate of return.  The results from this procedure do not imply that every predicted discovery determined to be commercially developable is worth exploring for.

     The basis for the estimates of recoverable undiscovered petroleum as a function of price is that the incremental units of exploration, development, and production effort will not occur unless the expected revenues from the eventual production will cover the incremental costs, including a normal return on the incremental investment.  Exploration is assumed to continue until the incremental cost of drilling wildcat wells is equal to or greater than the net present value of the cost of the commercially developed fields discovered by the last increment of wildcat wells.  For the last increment of oil and gas produced from a field, operating costs (including production related taxes) per barrel of oil equivalent are equal to net well-head price.

     These two assumptions together imply that for the commercially developable resources discovered by the last economic increment of wildcat wells (that is, for those reserves found, developed and produced at the economic margin), the sum of finding costs and development and production costs per barrel equals the well-head price.  These costs are called the marginal finding costs and the marginal development and production costs. 

     The marginal finding costs are calculated by dividing the cost of the last increment of wildcat wells (which is approximately equal to the sum of the after-tax net present value of all commercially developable fields discovered in that last increment of exploration) by the volume of economic resources discovered by the last increment of exploration.  Marginal development and production cost per barrel (for the economic resources discovered in that last increment of exploration) are calculated by subtracting the marginal finding costs from the well-head price.     

     Finding rate functions provide the critical link between field development costs and exploration costs.  For this study, the size, depth, and number of undiscovered accumulations were computed from the geologic assessment data.  However, finding rate functions determine the ordering of new discoveries and the rates at which new accumulations are found as a function of cumulative wildcats drilled in a particular depth interval.  A consistent set of finding rate coefficients could not be calculated for Northern Alaska but a procedure for obtaining default coefficients is described in Attanasi and Bird (1996).  Allocations of wildcat wells by depth interval were made in such a way that the after-tax net present value of the oil fields discovered was maximized for each increment of wildcat wells evaluated.

Incremental Costs: Results and Interpretations

     The full costs of bringing undiscovered oil resources to market include finding, development, production, and, in the case of Northern Alaska, transportation costs.  Incremental costs are linked to development, production, and transportation cost by finding rate functions that predict the discovery size distributions generated by increments of wildcat wells (Attanasi and Bird, 1996).  For this study, computations were based on successive increments of 20 wildcat wells.   Figure 5 presents the incremental cost functions for crude oil for the Federal NPRA based on the undiscovered accumulation size distributions associated with the 95th fractile, the mean, and 5th fractile estimates.  Table 4 summarizes the sub-area estimates of incremental costs, expected reserve additions, and finding costs.  Along with crude oil, the Table 4 also shows the associated gas liquids in developable oil discoveries.

     Figure 5 shows the differences in incremental costs that result from the different accumulation frequency-size distributions associated with estimates of the 95th fractile, the mean, and 5th fractile of the NPRA oil distribution.  As noted earlier, most of the differences in the distributions are in the numbers of fields rather than the sizes. The preponderance of fields is smaller than 250 million barrels.  Small fields are typically more costly to find and once found they may not even be commercially developable.  The threshold prices at which wildcat drilling and development starts are $22.40 per barrel for the 95th fractile distribution, $21 per barrel for the distribution associated with the mean, and $20.10 per barrel for the distribution associated with the 5th fractile estimate.  The incremental cost functions show large additions to reserves as prices increase beyond the trigger prices that allow marginal fields (less than 500 million barrels, see Table 2) to be commercially developed.

     For the mean and 5^th fractile distributions at $21 per barrel, 0.43 BBO and 2.23 BBO are economic to find, develop, produce, and transport to markets. This amounts to 5 percent and 17 percent of the technically recoverable oil assessed at the mean and 5^th fractile.  At $30 per barrel, 60 percent of the assessed technically recoverable oil for the mean is economic, 69 percent for the 5th fractile is economic, and 49 percent of the assessed oil for the 95th fractile is economic.  Table 4 shows that sub-areas 110 and 120 dominate the estimated economically recoverable oil.

Conclusions and Limitations

    Technically recoverable oil resources assessed in the Federal part of the NPRA study area at the 95^th and 5^th percentile are 5.9 and 13.2 BBO, respectively. The mean technically recoverable oil amounted to 9.3 BBO, which represented about 88 percent of the assessed technically recoverable oil in the total study area that included the Federal part of the NPRA, native lands within the NPRA, and lands underlying Alaska State waters. The underlying undiscovered accumulation size distributions showed that less than 40 percent of the assessed oil was assigned to accumulations having at least 250 million barrels of recoverable oil.

     Because of the relatively small sizes of the accumulations and the absence of infrastructure, the commercial development of discoveries will be challenging.  At a market price of $25 per barrel, the range of economically recoverable oil is from 1.6 BBO to 6.2 BBO with a mean of 3.7 BBO.    The regional play assessment provided only limited spatial information about locations of prospects, so the possibility remains that small fields might be developed using drill pads and infrastructure of the larger fields.  Moreover, particular operators may have special knowledge or experience that could significantly enhance the finding efficiencies assumed in this study.  Whereas the uncertainty attached to the geologic assessment is evident by the differing quantities of oil at alternative probabilities, there are also significant un-quantified uncertainties about the economic evaluation by virtue of the many assumptions made and the very limited empirical data on oil resource development in the NPRA.  

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Tables

Table 1. Mean value of undiscovered technically recoverable conventional oil, natural gas, and natural gas liquids (NGL) in the Federal part of the National Petroleum Reserve Alaska study area by play as of May 2002 (BBO= billion barrels of oil, TCF= trillion cubic feet of gas, BBL= billion barrels of natural gas liquids).

                                                                  OIL ACCUMULATIONS       GAS ACCUMULATIONS

                                                                   OIL          GAS         NGL           GAS       NGL

Table 2. Cumulative percentage distribution of estimated technically recoverable oil; Federal lands of the National Petroleum Reserve Alaska study area by oil field size class.

Table 3. Assessed mean technically recoverable oil, associated gas, and natural gas liquids (NGL) in undiscovered oil accumulations on Federal lands of the National Petroleum Reserve Alaska study area distributed by economic sub-area. (BBO= billion barrels of oil, TCF = trillion cubic feet gas, BBL = billion barrels of natural gas liquids, assoc. = associated gas).

Table 4. Incremental costs of finding, developing, producing, and transporting oil and natural gas liquids (NGL) from undiscovered oil accumulations in the Federal part of the National Petroleum Reserve Alaska study area and the estimated finding costs corresponding 95^th and 5^th fractile estimate and mean estimate of technically recoverable oil (BB0 = billion barrels of oil, BBL-billion barrels of NGL).

              F₉₅                     Mean                    F₅      

   110  18   0.00   0.00   0.00    0.00   0.00   0.00    0.00   0.00   0.00

        21   0.00   0.00   0.00    0.43   0.01   0.39    1.18   0.02   0.35

        24   0.66   0.01   0.60    1.48   0.03   0.50    2.82   0.06   0.71

        27   1.20   0.03   0.97    2.22   0.05   1.05    3.73   0.08   0.98

        30   1.35   0.03   1.26    2.52   0.05   1.33    3.90   0.08   1.24

        33   1.54   0.03   2.09    2.63   0.06   1.71    4.10   0.09   2.09

        36   1.61   0.03   2.70    2.71   0.06   2.22    4.16   0.09   2.70

   120  18   0.00   0.00   0.00    0.00   0.00   0.00    0.00   0.00   0.00

        21   0.00   0.00   0.00    0.00   0.00   0.00    1.05   0.02   0.39

        24   0.58   0.01   0.68    1.32   0.03   0.56    2.30   0.05   0.55

        27   1.07   0.02   1.08    1.99   0.04   1.12    3.36   0.07   1.05

        30   1.21   0.03   1.42    2.30   0.05   1.39    3.54   0.07   1.30

        33   1.40   0.03   2.21    2.40   0.05   1.77    3.73   0.08   2.18

        36   1.46   0.03   2.85    2.48   0.05   2.30    3.79   0.08   2.81

   130  18   0.00   0.00   0.00    0.00   0.00   0.00    0.00   0.00   0.00

        21   0.00   0.00   0.00    0.00   0.00   0.00    0.00   0.00   0.00

        24   0.00   0.00   0.00    0.27   0.01   0.61    0.68   0.01   0.59

        27   0.15   0.00   1.10    0.58   0.01   1.29    0.99   0.02   1.29

        30   0.31   0.01   1.55    0.78   0.02   1.52    1.26   0.03   1.57

        33   0.40   0.01   1.74    0.88   0.02   2.00    1.37   0.03   1.87

        36   0.47   0.01   2.43    0.95   0.02   2.42    1.45   0.03   2.32

   210  18   0.00   0.00   0.00    0.00   0.00   0.00    0.00   0.00   0.00

        21   0.00   0.00   0.00    0.00   0.00   0.00    0.00   0.00   0.00

        24   0.00   0.00   0.00    0.00   0.00   0.00    0.00   0.00   0.00

        27   0.00   0.00   0.00    0.00   0.00   0.00    0.13   0.00   1.33

        30   0.00   0.00   0.00    0.00   0.00   0.00    0.24   0.01   1.54

        33   0.00   0.00   0.00    0.19   0.00   2.24    0.41   0.01   1.81

        36   0.00   0.00   0.00    0.28   0.01   2.53    0.50   0.01   2.14

   220  18   0.00   0.00   0.00    0.00   0.00   0.00    0.00   0.00   0.00

        21   0.00   0.00   0.00    0.00   0.00   0.00    0.00   0.00   0.00

        24   0.00   0.00   0.00    0.00   0.00   0.00    0.00   0.00   0.00

        27   0.00   0.00   0.00    0.00   0.00   0.00    0.14   0.00   1.28

        30   0.00   0.00   0.00    0.00   0.00   0.00    0.22   0.00   1.92

        33   0.00   0.00   0.00    0.08   0.00   2.07    0.22   0.00   1.92

        36   0.00   0.00   0.00    0.08   0.00   2.07    0.33   0.01   2.22

   230  18   0.00   0.00   0.00    0.00   0.00   0.00    0.00   0.00   0.00

        21   0.00   0.00   0.00    0.00   0.00   0.00    0.00   0.00   0.00

        24   0.00   0.00   0.00    0.00   0.00   0.00    0.00   0.00   0.00

        27   0.00   0.00   0.00    0.00   0.00   0.00    0.00   0.00   0.00

        30   0.00   0.00   0.00    0.00   0.00   0.00    0.00   0.00   0.00

        33   0.00   0.00   0.00    0.00   0.00   0.00    0.00   0.00   0.00

        36   0.00   0.00   0.00    0.00   0.00   0.00    0.00   0.00   0.00

TOTAL   18   0.00   0.00   0.00    0.00   0.00   0.00    0.00   0.00   0.00

        21   0.00   0.00   0.00    0.43   0.01   0.39    2.23   0.05   0.37

        24   1.25   0.03   0.64    3.07   0.06   0.54    5.80   0.12   0.63

        27   2.43   0.05   1.03    4.78   0.10   1.11    8.34   0.17   1.05

        30   2.87   0.06   1.36    5.60   0.12   1.38    9.17   0.19   1.33

        33   3.35   0.07   2.10    6.17   0.13   1.80    9.82   0.21   2.08

        36   3.54   0.07   2.73    6.50   0.14   2.29   10.23   0.21   2.64