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The economics of petroleum exploration and development west of Scotland
Continental Shelf Research 21 (2001) 1095–1120
The economics of petroleum exploration and development west of Scotland Alexander G. Kemp*, Linda Stephen Department of Economics, University of Aberdeen, Edward Wright Building, Dunbar Street, Aberdeen AB24 3QY, UK Received 13 September 1999; accepted 10 October 1999
Abstract This paper examines the economics of oil and gas exploration and development in the West of Scotland region. A considerable exploration effort has resulted in some discoveries but the overall success rate has been quite low. The region is comprised of several distinct geological basins. To date the Judd Basin has experienced the best discovery rate. Expected returns as measured by expected monetary values are generally low, confirming the high-risk nature of the region. The most economical field development concept depends to a large extent on a combination of field size and water depth which vary markedly from basin to basin. In typical cost conditions at an $18 price returns to investors in medium and large-sized fields at the development phase are positive, but at $14 only when costs are relatively low are positive returns in prospect. Stand-alone gas developments are very unlikely to be viable in current market conditions. The fuller exploitation of the whole region requires higher oil and gas prices and /or significant innovation and technological progress. # 2001 Published by Elsevier Science Ltd. Keywords: Geological basins; West of Scotland; Exploration risk; Expected monetary values; Net present values; Oil and gas developments
1. Introduction The environment for petroleum exploitation West of Scotland is generally described as frontier. The term is used rather loosely, but is normally understood to refer to characteristics such as limited geological knowledge, high exploration risk, difficult operating conditions such as very deep water, strong gales and currents, large waves, and lack of infrastructure. All characteristics apply to West of Scotland.
*Corresponding author. Tel.: +44-01224-272168; fax: +44-01224-272181. E-mail address: [email protected] (A.G. Kemp). 0278-4343/01/$ - see front matter # 2001 Published by Elsevier Science Ltd. PII: S 0 2 7 8 - 4 3 4 3 ( 0 0 ) 0 0 1 2 6 - 6
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To obtain a proper understanding of the economic aspects of oil and gas exploitation requires consideration of all these features. Further complications with respect to the West of Scotland region are (a) the highly variable water depths, and (b) the presence of several distinct geological basins. In addition some basins have been subject to a substantial amount of exploration while to date others have experienced little or none. This paper takes account of all these factors and provides an analysis of the prospective returns at (a) the exploration stage and (b) the field development stage. These are the key investment decision points in the decision-making process in the petroleum industry (Kemp and Stephen, 1998).
2. Methodology and data 2.1. Exploration The exploration prospects are assessed by the estimation of expected monetary values (EMVs) employing the Monte Carlo technique. EMVs highlight the risks and the range of possible outcomes from the exploration activity. Appraisal risk is included in the study to reflect the possibility that a discovery will be so small that its development is uneconomic even at ‘‘high’’ oil prices. The general form of the model is shown schematically in Fig. 1. The model postulates an exploration success rate, an appraisal success rate and a distribution of field sizes. This is lognormal, reflecting the general experience in all petroleum provinces. For discoveries made there is a range of field development costs and operating costs. The distributions for both of these are presumed to be normal. The UK oil price is also modelled as stochastic with normal distribution and time dependency characteristics. The distribution for each stochastic variable is defined by a specified mean and standard deviation. The study examines the different geological basins separately and estimates the EMVs for each. There are some common and some separate assumptions employed. The variations reflect the different known characteristics of each basin.
Fig. 1. Schematic P representation of investment situation facing explorationist. In the circumstances described above the i¼n EMV ¼ pcd i¼1 prob: NPVfl E psdA:
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Fig. 2. Development costs with mean values, standard deviation and minimum and maximum values. The standard deviation was set at 12.50% of the mean.
Common assumptions include a total exploration and appraisal cost of $60 million with $20 million being spent on exploration in 1998, $20 million on appraisal in the year 2000, a further $20 million in 2002 and any subsequent field development occurring immediately after this. In the first instance it is assumed that because of lack of nearby infrastructure, any reserves found could only be developed on a stand-alone basis, and that only an oil find of greater than 50 million barrels (mmbl) would be developed. Thus any oil field with reserves of less than 50 million barrels or a gas field of any size would not be developed. For purposes of this part of the study, field developments by FPSO are assumed. Development costs were with mean values, standard deviation and minimum and maximum values as in Fig. 2. Annual operating costs were modelled as a percentage of accumulated development costs. The mean value was 10%. The standard deviation was set at 12.5% of the mean. Minimum and maximum values were set at 10 and 14%, respectively, of accumulated investment costs. The oil price was set at $18 in the initial period corresponding to first exploration. The standard deviation was set at 10% of the mean value, but price behaviour through time was modelled as time-dependent thus permitting rising or falling trends. Minimum and maximum values were set at $5 and $35, respectively. Given the very considerable uncertainties two cases of reserves size distributions were examined, both are lognormal. The first has a mean value of 150 million barrels and the second 100 million barrels. The standard deviation is 75% of the mean value. Historical exploration experience in the different basins was employed to determine appropriate values for making future estimates. The Judd Basin has been the most intensively explored and prospective. Foinaven, Schiehallion, Loyal, Suilven, Alligin and Conival have all been discovered in this area. The overall exploration success rate has been 29%. If gas discoveries are excluded the success rate is 25%. Perhaps two-thirds of the oil discoveries can be regarded as potentially commercial. In the West Shetland Basin at least 34 exploration wells have been drilled. The Clair and Victory fields are located in this basin as is another gas find. An overall exploration success rate of 8.8% reflects the position to date, but for oil alone it is only 2.94%. In the Rona-Flett Basin there have been 21 known exploration wells to date. The Larkspur, Newton and Lister discoveries are in this area. This gives a success rate of 14.3%, but the oil exploration success rate falls to 4.8%. In the Faroes Basin 16 known exploration wells have been drilled. The Torridon and Laggan gas finds are in this area. In the West Hebrides Basin 6 exploration wells have been drilled without known success. In the Foula Basin one well has been drilled.
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2.2. Results The calculations were conducted under the assumptions for success rates discussed above plus some additional sensitivities. Summary results showing the mean EMVs at different discount rates where the mean reserves from discoveries are 150 million barrels are shown in Fig. 3. For the case where the mean size of discovery is 100 million barrels the results are shown in Fig. 4. It is seen that positive returns are in prospect in only a minority of cases. The Judd Basin is the most attractive when the historic exploration success rates are employed. Given that this basin is relatively well-explored, it is possible that prospectivity in the future may be less than to date. Thus the results are shown for the case where the exploration success rate fell to 10%. These generally pessimistic results relate to the mean expected returns. It may well be that explorationists are generally optimistic regarding the chances of discovery. The Monte
Fig. 3. Mean expected post-tax EMVs under different assumptions.
Fig. 4. Mean expected post-tax EMVs under different assumptions.
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Carlo techniques provide much more information in the possible range of prospective returns. The full distribution of returns for the Judd Basin are shown in Fig. 5 for the case where the mean size of discovery is 150 million barrels. For an explorationist who is an optimist even with the historic success rates, it is seen that the post-tax EMV could be very substantial. There is a 30% chance that it will exceed $27 million and a 20% chance that it will exceed $41 million. On the other hand there is a 40% chance that the EMV will be negative. There is a 68% chance that it is in the $17 million to +$50 million range. Where the mean size of discovery is 100 million barrels there is a 68% chance that the post-tax EMV will be in the $18 million to +$25 million range. In this case there is a 30% chance that the EMV will exceed $10 million and a 40% chance that it will be negative.
Fig. 5. Judd Sub Basin}Initial oil price $18/bl, mean reserves 150 mmbl.
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In the Solan Basin with the mean size of discovery at 100 million barrels and success rates based on historic performance there is a 30% chance that it will be positive, a 20% chance that it will exceed $5.5 million, and a 10% chance that it will exceed $15 million. There is a 68% chance that it will be between $16 million and +$9 million. In the West of Shetland Basin with 10% exploration success and mean size of discovery of 150 million barrels the expected returns at the 68% probability level are all negative. This finding was also present for the Rona-Flett Basin. These findings were on the basis of 10% real discount rate. For exploration West of Scotland higher rates can certainly be justified given the risks involved. The conclusions are thus that exploration in this part of the UKCS is certainly high risk and the chances of losses substantial.
3. Development economics } oil 3.1. Methodology and assumptions } general The development economics of oil discoveries are now discussed. There are various development concepts available, particularly (1) FPS0, (2) conventional fixed platform and (3) tension leg platform (TLP). From an economic viewpoint the choice depends on a number of factors. To date FPSOs have been employed. They have some perceived advantages with respect to flexibility and versatility. There are also problems with this technology. There may be capacity limits. Currently they can sustain production of at least 140,000 barrels/day, but much higher output levels could require processing facilities on a scale difficult to accommodate on the vessel. In this paper emphasis is given to the comparative costs of oil exploitation via the three development options. Generally there are some economies of scale with respect to all the schemes. The extent of these varies, however, with the constraints on FPSOs noted above being an example. The relative costs also depend on other factors particularly water depth. Broadly, when FPSOs and TLPs are employed development costs do not vary dramatically with water depth, though some increase can be expected. On the other hand costs of development with a conventional fixed platform vary very substantially with water depth. A further complication relates to operating costs. For developments employing FPSOs these are somewhat higher than for platforms. Of course, tariffs payable for tanker transportation add considerably to overall operating costs. In the present study tanker charges to Sullom Voe or Flotta are included in the operating costs relating to the FPSO option. Total annual operating costs are modelled to range from 9.5% of accumulated development costs on a field of 100 million barrels to 6% on a field of 600 million barrels. 3.2. Assumptions } Judd Basin Two detailed case studies were undertaken, namely relating to the Judd Basin and the West of Shetlands Basin. They were chosen because they are of most current interest and because they illustrate the importance of water depth in the comparative economics of developments. In the Judd Basin discoveries have been made in water depths in the range 350–600 m with distances
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from shore in the range 140–210 km. A development in 400 m of water and 180 km from shore was chosen for detailed analysis. At this water depth in terms of field development cost FPSOs should constitute the cheapest option for the likely sizes of field. Clearly there will be a considerable range of development costs for all options. A possible minimum for the FPSO option in this water depth (reflecting very favourable circumstances) could range from around $4 per barrel for a 400 million barrel field. For significantly larger fields 2 vessels might be required and the minimum for a field of 600 million barrels could be $2.25 per barrel. Minimum development costs with a platform development were estimated to range from around $7.9 per barrel for a field of 100 million barrels to $3.6 per barrel for a field of 400 million barrels and perhaps $2.8 per barrel for one of 600 million barrels. For fields with reserves exceeding 200 million barrels the TLP concept is cheaper than a conventional platform. Again these figures relate to situations where all the circumstances regarding the development proceed favourably. Pipeline costs are excluded from the above. These have been examined and two cases considered. The first relates to a medium-sized pipeline (1800 diameter) over 180 km with 25 km lying in relatively deep water. This pipeline (including tie-in costs) was estimated to cost $113 million. The second case is a large pipeline of 3000 diameter. This is deliberately over-sized to accommodate the possibility of future third-party tariffing. The estimated cost (including tie-in cost) was estimated at $243 million. When these costs are added to the field investment cost the minimum total development cost using the platform option for the 100 million barrel field is around $9.45 per barrel with the 1800 pipeline and $10.75 per barrel with the 3000 line. The corresponding figures for a 300 million barrel field are $4.63 and $5.1 per barrel. For a 600 million barrel field they are $2.96 and $3.2 per barrel. Operating costs are somewhat less with the platform option. On an annual basis these have been estimated at 7.5% of accumulated field development costs for the 100 million barrel field, 5.5% on the 300 million barrel field, and 4% on a 600 million barrel field. 3.3. Results } Judd Basin The returns to investors in the Judd Basin in a selection of fields are now examined. The returns are shown in terms of post-tax net present values (NPVs) at 10% real discount rate. Oil prices of $18 and $14 in real terms have been employed. In Figs. 6 and 7 such returns are shown for the 150 million barrel field. Under the $18 price it is seen that with the FPSO concept potential returns are significantly positive when development costs are in the range $3.5–$6.5 per barrel. A TLP development would not be possible except at the highest part of the cost range shown. Because of the lower operating costs such a development with the 1800 pipeline could produce an NPV at least as large as that with the FPSO. If a large pipeline were employed the NPV becomes negative. Under the $14 oil price the NPVs are substantially positive with FPSO developments when investment costs are $5 or less per barrel. At higher costs returns are negative. A TLP development would not be viable at all under this oil price. For fields significantly smaller than 150 million barrels it was found that only FPSOs offered the possibility of positive returns and then only in limited circumstances. The development of a 100
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Fig. 6. Post-tax RNPV at 10% Judd Basin, 150 mmbl field oil price $18.
Fig. 7. Post-tax RNPV at 10% Judd Basin, 150 mmbl field oil price $14.
million barrel field offered worthwhile returns under the $18 price with investment costs in the $4.5–$6.5 per barrel range. Under the $14 price returns were found to be positive only when development costs were $5 per barrel or less. Investment in a 200 million barrel field was found to produce substantially positive returns under the $18 price using FPSO technology when development costs were in the $3–$6.5 per barrel range. A TLP development with an 1800 pipeline could be viable if the total investment cost were in the $6–$7.20 range. In such cases the returns were found to be comparable to those with
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FPSO developments involving investment costs of $5.5–$6.5 per barrel. Under the $14 price only FPSO developments were found to offer positive returns and then only when investment costs were $5 per barrel or less. The returns to an investment in a 300 million barrel field are shown in Figs. 8 and 9. Under the $18 price using FPSO technology substantial returns are attainable with development costs in the $2.5–$6.5 per barrel range. On this size of field a TLP development with 1800 pipeline would produce worthwhile positive returns when total investment costs are in the $4.90–$6.90 per barrel range. In fact the returns would then be higher than those from a comparable FPSO development with field investment costs in the $4.50–$6.50 per barrel range. Under the $14 price returns to the investor are substantially positive using the FPSO option with field development costs of $5 per barrel or less. At higher unit investment costs the project’s economic viability becomes doubtful. It is noteworthy that at such levels of development costs the returns are generally higher with the TLP option, especially when the medium-sized pipeline is employed. The results for a field of 400 million barrels are shown in Figs. 10 and 11. Using the FPSO development concept returns to the investor under the $18 price are very substantially positive with development costs as high as $6.5 per barrel. When the TLP concept is employed it is seen that in the development cost range $4.50–$6.50, this alternative produces somewhat higher returns when the medium-sized pipeline is employed. Under the $14 price scenario returns to the investor are positive with FPSO technology when development costs are $5.50 per barrel or less. It is again noticeable that when development costs exceed $4.50 per barrel the TLP option with a medium-sized pipeline produces higher returns than the FPSO technology. At even higher levels of reserves the economic case for the TLP option becomes progressively stronger. Thus in cases of fields with 500 and 600 million barrels of reserves the unit cost of a TLP
Fig. 8. Post-tax RNPV at 10% Judd Basin, 300 mmbl field oil price $18.
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Fig. 9. Post-tax RNPV at 10% Judd Basin, 300 mmbl field oil price $14.
Fig. 10. Post-tax RNPV at 10% Judd Basin, 400 mmbl field oil price $18.
development became very competitive with that of the FPSO, and for most likely cost conditions the returns to the investor were greater. The general conclusion, however, is that for smaller and medium-sized field the FPSO option is likely to be the more economic option. Even for fields as large as 300 or 350 million barrels the FPSO option offers the prospect of higher returns because quite low-cost developments are possible with this technology.
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Fig. 11. Post-tax RNPV at 10% Judd Basin, 400 mmbl field oil price $14.
3.4. Assumptions } West Shetland Basin In the West Shetland Basin, where several discoveries including Clair and Victory have been made, the water depths are much less than in the Judd Basin. The known discoveries are in water depths in the range 125–385 m, 76–122 km from Shetland. For purposes of this study the development economics of a discovery in 150–200 m of water 80 km from shore are examined. In such conditions the cost advantages of the FPSO option are considerably reduced. In this water depth the minimum development cost under this option for a field of 100 million barrels could be around $3.50 per barrel, progressively falling to $2.60 with a field of 200 million barrels, $2.25 at 300 million and $2.0 at 400 million barrels. For this water depth a fixed conventional platform development is generally cheaper than the TLP concept. The minimum development cost with the 1800 pipeline is estimated at $4.0 per barrel for a field with reserves of 100 million barrels, $2.90 for a field with 200 million, $2.54 for 300 million, and $2.2 for a 400 million barrel one.
3.5. Results } West Shetland Basin The prospective returns to an investor in a field of 150 million barrels are shown in Figs. 12 and 13. Under the $18 price case the returns are positive with all development options for development costs as high as $6.90 per barrel. It is noteworthy that the returns are higher with the fixed platform option and the 1800 pipeline. This size of pipeline is also sufficiently large to permit thirdparty transportation from other fields. Under the $14 price scenario the returns to the investor are positive when development costs are $5 per barrel of less. It is again seen that the NPVs are higher with the platform option.
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Fig. 12. Post-tax RNPV at 10% West of Shetland Basin, 150 mmbl field oil price $18.
Fig. 13. Post-tax RNPV at 10% West of Shetland Basin, 150 mmbl field oil price $14.
The next case examined is a field with recoverable reserves of 200 million barrels. The returns to the investor are shown in Figs. 14 and 15. Under the $18 price the NPVs are all substantially positive under both development options. It is seen that the returns are generally higher with the platform development option and the 1800 pipeline. In some of the cost cases the combination of the platform with the 3000 pipeline is competitive with the FPSO option.
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Fig. 14. Post-tax RNPV at 10% West of Shetland Basin, 200 mmbl field oil price $18.
Fig. 15. Post-tax RNPV at 10% West of Shetland Basin, 200 mmbl field oil price $14.
Under the $14 price the project produces positive returns under both development options when development costs are $5 per barrel or less. Again the platform option with 1800 pipeline produces the higher NPVs. The next case is a field of 400 million barrels. The returns to the investor are shown in Figs. 16 and 17. Under the $18 price for the whole range of development costs shown the NPVs are very substantially positive under the different development options. The platform option generally produces the higher returns. On this field the investment in the larger pipeline is seen to produce higher returns than the FPSO option.
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Fig. 16. Post-tax RNPV at 10% West of Shetland Basin, 400 mmbl field oil price $18.
Fig. 17. Post-tax RNPV at 10% West of Shetland Basin, 400 mmbl field oil price $14.
Under the $14 price returns to the investor are positive with development costs as high as $.5.50 per barrel (plus pipeline costs). Again the platform option generally produces the higher returns. The general conclusion from this part of the study is that from an economic viewpoint a platform-based development is much more feasible in the West of Shetland Basin than was the case in the Judd Basin. Further, a conventional platform will generally have cost advantages over a TLP. The choice of option becomes more difficult on smaller fields where FPSOs sometimes
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have the cost advantage. On quite small fields (less than 100 million barrels) exploitation will be uneconomic by either development option even in this moderate water depth, especially under a $14 price. 3.6. Subsea development plus use of common infrastructure } assumptions In the North Sea many small fields are rendered economic via the use of existing infrastructure. Although very little infrastructure currently exists West of Scotland it is useful to consider such a future possibility. This provides some basis for the analysis of the future development economics of smaller fields. The hypothetical case examined is one where a field is developed with a subsea system tied back to an established facility which processes and exports the oil. The case of infrastructure comprising a platform and pipeline is considered but the basic ideas also apply to an FPSO and tanker transport. Two examples are examined when the distances between the subsea development and the host platform are 15 and 30 km. Tariffs for processing and transportation are set at £1 per barrel with a sensitivity case of £2 per barrel. The estimated minimum field investment costs for subsea development in West of Scotland conditions were set at $7 per barrel for a 25 million barrel field falling to $4.10 for one of 50 million barrels, and $2.8 for one of 100 million barrels. When the capital costs of a 25 km flowline are included the total minimum estimated development costs for the 3 cases increase to $7.52, $4.32 and $2.91 per barrel. If the flowline were 30 km the minimum investment costs for the 3 fields increase to $7.84, $4.48, and $3 per barrel. Annual operating costs are estimated at 8.5% of accumulated investment costs for the 25 and 50 million barrel fields and 7.5% for the 100 million barrel one. 3.7. Subsea developments with tie-ins } results The NPVs for the projects as described above were calculated. By way of comparison the returns to the projects are also shown when they were developed with stand-alone FPSOs and platform plus pipelines under West of Shetland conditions. It was found that the returns to the 25 million barrel field were negative. They are not shown here. The returns to the 50 million barrel project are shown in Figs. 18 and 19. Under the $18 price it is seen that when developed on a subsea basis the project offers positive returns when the tariff is £1 per barrel over a plausible range of development costs from $4.6to $6.5 per barrel. This remains the case when the distance from the platform is 30 km. When the tariff is £2 per barrel the returns remain positive over the same investment cost range under the low tariff. Under the high tariff the NPVs are negative at development costs of $6.5 per barrel. Returns are also positive for development via FPSOs and platforms in moderate water depths for development costs in the $5.5–$6.4 per barrel range. Under the $14 price scenario the picture is very different. The returns under most of the conditions examined are negative. Only under the lower levels of cost examines is the project viable.
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Fig. 18. Post-tax RNPV at 10% Subsea tie-in, 50 mmbl field oil price $18.
Fig. 19. Post-tax RNPV at 10% Subsea tie-in, 50 mmbl field oil price $14.
The results for the 100 million barrel project are shown in Figs. 20 and 21. Under the $18 price scenario the returns are positive under all the combinations examined for development costs as high as $6.5 per barrel. Under the $14 price case the returns under all combinations are positive with developments costs of $4.5 per barrel or less. At development costs of $5 per barrel the returns are positive in all cases except those with the high tariff. At development costs of $5.5 per barrel more returns are negative.
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Fig. 20. Post-tax RNPV at 10% Subsea tie-in, 100 mmbl field oil price $18.
Fig. 21. Post-tax RNPV at 10% Subsea tie-in, 100 mmbl field oil price $14.
The main conclusions of this section are that subsea development can render viable some fields which would otherwise have been uneconomic. It remains the case, however, that some projects which might well be viable in North Sea conditions would remain sub-economic in West of Shetland conditions. The size of the tariff payable can be important in determining the viability of some projects and in determining whether a subsea tie-in or stand-alone development is the more economic concept.
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4. Development economics } gas 4.1. Location and possible development/operating costs } general Gas has been discovered in several area West of Shetland. The Torridon and Laggan fields are in the Faroes Basin. The Larkspur, Newton and Lister discoveries are discoveries in the RonaFleet Basins. The Victory discovery is in the West Shetland Basin. The Conivial discovery is located in the Judd Basin. As was discussed for oil exploitation for water depths of less than 200 m or so a conventional platform development is generally cheaper than a TLP. In very deep waters the TLP becomes very much more economic. In this part of the study the cheaper investment option has been determined for the typical water depths in the different basins. The minimum possible investment costs have been estimated and a further case of this minimum plus 25% included in the analysis. Gas may be used in many ways. In this study the emphasis is on its possible use in the UK gas market in a conventional manner with pipeline transport. The general methodology employed was to calculate the possible combinations of reserves and gas prices required to permit the recovery of all investment costs plus a minimum return on that investment. This was set at 10% post-tax in real terms. 4.2. Judd Basin } assumptions In this basin cases of field developments in 500 m of water were examined. The TLP concept is clearly cheaper than a conventional platform in such conditions. The minimum field development cost (excluding pipelines) in this water depth was estimated at 17.3 pence per therm for a 300 bcf field, falling to 10.4 pence for one of 600 bcf, 7.3 pence for 1 tcf, and 4.7 pence for 2 tcf and still larger field. Pipeline costs (including tie-in costs) were estimated to (a) a landfall point in Orkney, (b) to the FLAGGS trunk line and (c) to the Frigg trunk line. These vary according to pipeline diameter. For a 2200 pipeline the cost to Orkney was estimated at $184 million, to FLAGGS $257 million, and to the Frigg line $295 million. For a 3200 line the corresponding costs were estimated at $267, $374, and $430 million. For a 4000 line the corresponding costs were set at $334, $468, and $539 million. Tariffs from these pipeline systems to the St. Fergus terminal were estimated at 40 pence per mcf in both cases. 4.3. Judd Basin } results The results for the case where the gas is landed in Orkney are shown in Fig. 22. It is seen that, depending on the investment cost the gas price necessary to recover costs plus a 10% return, ranges from 45–53 pence per therm for a 300 bcf field to 15–20 pence for fields in the 2–6 tcf range. It is likely that investors would require a higher expected return to compensate for the risks involved. There is currently no significant gas market in Orkney. The scenario where the gas is landed at St. Fergus is thus of more interest. The results for the case where the gas was linked into the FLAGS line and then taken to St. Fergus are shown in Fig. 23. The price required at St. Fergus
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Fig. 22. Judd Basin to Orkney (water depth 500 m, TLP).
Fig. 23. Judd Basin to FLAGS (water depth 500 m, TLP).
varies according to the investment cost from 32–37 pence for a 1 tcf field to 19–25 pence for very large fields. These figures relate to a relatively low return on capital in relation to the risks. The results for the route via the Frigg pipeline were not significantly different from the FLAGS case.
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4.4. Faroes Basin } assumptions The exercise was repeated for gas fields in the Faroes Basin. In this case Shetland is the nearest landfall. Water depth of 400 m was assumed. The estimated pipeline costs to Shetland and the FLAGS and Frigg pipelines for a 2200 line were estimated at $114, $238, and $286 million, respectively. For a 3200 line the costs were estimated at $164, $346, and $416 million. For a 4000 line they were estimated at $205, $433, and $521 million, respectively. The results for the case where the gas is landed in Shetland are shown in Fig. 24. Depending on the field investment cost the price necessary to recover costs plus a 10% return are in the 42–51 pence range for a 300 bcf field, falling to 15–21 pence for 2 tcf and larger fields. The results for the case where the gas is piped to the FLAGS line and then to St. Fergus are shown in Fig. 25. For a field of 1 tcf the required price is in the 31–37 pence range depending on the field investment cost. For a 2 tcf field the range is 22–24 pence. For still larger fields requiring more platforms the price range is similar. As before these prices should be regarded as minimum given the risks involved. An alternative development scheme when gas is found in very deep water would be to locate the platform in shallower water and produce the gas from a series of subsea systems tied back to the platform. The saving in platform costs could be very substantial, particularly if it were to be located in water depths of 200 m or less. This saving could readily more than compensate for the costs of subsea systems and the associated flowline costs. 4.5. Rona-Flett Basin } assumptions In this basin discoveries have been made in a variety of water depths ranging from over 300 m to under 100 m. Case studies were conducted of developments in water depths of (a) 500 m and (b)
Fig. 24. Faroes Basin to Shetland (water depth 500 m, TLP).
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Fig. 25. Faroes Basin to FLAGS (water depth 500 m, TLP).
150 m. Cases of pipeline transportation to Shetland, the FLAGS line and the Frigg Line were examined. For a 2200 pipeline in 150 m of water the costs were estimated at $204 million to FLAGGS and $295 million to the Frigg line. For a 3600 line the corresponding costs were $330 and $479 million, and for a 4000 line $371 and $538 million. These figures are relatively high because, although the field is in relatively shallow water, the location of these waters is such that the distance is considerably greater than from the deep water location. 4.6. Rona-Flett Basin } results When the field was located in 500 m of water it was found that the results were not substantially different from those for the Faroes Basin. The minimum price required is a little lower in the Rona-Flett case. The results for the case where the field is located in 150 m are shown in Figs. 26 and 27. Where the gas is delivered to Shetland it is seen that the minimum price falls from 22 to 26 pence per therm for small fields to 10–13 pence for very large developments. If the gas were transported to FLAGS and then to St. Fergus the minimum price falls from 20– 22 pence for a 1 tcf field to 14–18 pence for much larger scale developments. 4.7. West Shetland Basin } assumptions At least 2 gas discoveries have been made in this area including the Victor field. Typical water depths are in the 150–200 m range. A case of a field located in 200 m of water around 80 km from Shetland was examined. For a 2200 line the costs to Shetland are estimated at $83 $106 million to the FLAGS line and $163 million to the Frigg line. For a 3600 line the corresponding costs are $131, $169 and $263 million. For a 4000 line they are $147, $190, and $295 million.
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Fig. 26. Rona-Flett Basin to Shetland (water depth 500 m, TLP).
Fig. 27. Rona-Flett Basin to FLAGS (water depth 500 m, TLP).
4.8. West Shetland Basin } results The required minimum prices for landings in Shetland and St. Fergus are shown in Figs. 28 and 29. The minimum price required for gas landed in Shetland was found to range from 23 to 27 pence for a 300 bcf field, to 15–17 pence for a 1 tcf field, and 10–14 pence for much larger ones.
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Fig. 28. West of Shetland Basin to Shetland (water depth 200 m, conventional platform).
Fig. 29. West of Shetland Basin to FLAGS (water depth 200 m, conventional platform).
For landings at St. Fergus the minimum price was found to be in the 19–22 pence range for a 1 tcf field falling to 14–17 pence for much larger ones. 4.9. West Hebrides } assumptions Water depths to the west of the Hebrides are much greater than in the other areas examined. Distances to landfalls are also very long. A case where fields were discovered in water depths of
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Fig. 30. West Hebrides to Orkney (water depth 1500 m, TLP).
1500 m located 580 km from Orkney was examined. A TLP development concept was employed. The pipeline costs for delivery in Orkney were estimated at $580 million for the 2200 line, $938 million for the 3600 line and $1 billion for the 4000 one. The pipeline costs for deliver to Barrow for the same sizes of pipeline were estimated at $864 million, $1.4 billion, and $1.6 billion. 4.10. West Hebrides } results The minimum required prices for landing gas at the 2 destinations are shown in Figs. 30 and 31. For Orkney these range from 60 to 70 pence for a 300 bcf field to 37–42 pence for a 1 tcf development, and 20–26 pence for much larger fields. For landings at Barrow the minimum prices was found to be in the 42–50 pence range for a 1 tcf development, falling sharply to 22–28 pence for large fields with reserves of 3 tcf or more.
5. Conclusions This paper has examined the economic aspects of oil and gas exploration and development in some detail. There is a considerable exploration history in the region going as far back as the early 1970s. A substantial number of wells have been drilled although overall success rate has been quite low. In the period 1988–1998 inclusive it has been only 8.8% for the whole region. The region comprises several distinct geological basins (unlike the area East of Shetland, for example). The prospects for each of the main basins were examined separately. Based on historic success rates exploration in the Judd Basin offered the best economic prospects. In most basins the mean expected returns facing an explorationist were negative. The evidence supports the view that the West of Scotland region should be regarded as high risk.
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Fig. 31. West Hebrides to Barrow (water depth 1500 m, TLP).
At the field development phase the position in the West of Scotland region is made more complex by the presence of a wide range of water depths which complicate the choice of development concept. To date FPSOs have been employed in the relatively deep waters in the Judd Basin. In shallower waters, such as in the West Shetland Basins, conventional platforms could be more economic. In deep waters for large discoveries the TLP could constitute the most economic concept. Under an $18 constant real oil price medium and large oil fields with plausible development costs should be economically viable. The use of the FPSO concept should produce the highest returns on medium-sized fields, but in large fields the TLP concept may be more attractive in situations where development costs are relatively high under all development options. The viability of small field developments with reserves of 50 million barrels or less is more problematic. With a $14 price the picture is quite different. Only with relatively low or moderate development costs are projects likely to be viable on a stand-alone basis. In this context it is noteworthy that many companies are assessing new investment projects at this and even lower prices. Subsea tieins offer some scope for the development of some fields which are otherwise uneconomic. Several gas discoveries have been made West of Scotland. The potential economic viability of these was examined by calculating the minimum gas prices required to make economically viable various combinations of reserves and costs (field plus pipeline) in different locations. The required delivered prices at St. Fergus were relatively high. An interesting finding from the analysis of the investment cost structures was the relatively moderate share taken by very long pipelines even in deep water. Generally the implications of the study are that ‘‘higher’’ oil and gas prices and/or significant innovations and technological advances are required for fuller exploration and development. Higher prices certainly cannot be guaranteed. If the region’s potential is to be fully exploited
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development of new technologies and the wider diffusion of recent advances are likely to be necessary. References Kemp, A.G., Stephen, L., 1998. The Economics of Oil and Gas Exploration and Development. North Sea Study Occasional Paper No. 67. Department of Economics, University of Aberdeen,West of Scotland, September, 143pp.
The economics of petroleum exploration and development west of Scotland Alexander G. Kemp*, Linda Stephen Department of Economics, University of Aberdeen, Edward Wright Building, Dunbar Street, Aberdeen AB24 3QY, UK Received 13 September 1999; accepted 10 October 1999
Abstract This paper examines the economics of oil and gas exploration and development in the West of Scotland region. A considerable exploration effort has resulted in some discoveries but the overall success rate has been quite low. The region is comprised of several distinct geological basins. To date the Judd Basin has experienced the best discovery rate. Expected returns as measured by expected monetary values are generally low, confirming the high-risk nature of the region. The most economical field development concept depends to a large extent on a combination of field size and water depth which vary markedly from basin to basin. In typical cost conditions at an $18 price returns to investors in medium and large-sized fields at the development phase are positive, but at $14 only when costs are relatively low are positive returns in prospect. Stand-alone gas developments are very unlikely to be viable in current market conditions. The fuller exploitation of the whole region requires higher oil and gas prices and /or significant innovation and technological progress. # 2001 Published by Elsevier Science Ltd. Keywords: Geological basins; West of Scotland; Exploration risk; Expected monetary values; Net present values; Oil and gas developments
1. Introduction The environment for petroleum exploitation West of Scotland is generally described as frontier. The term is used rather loosely, but is normally understood to refer to characteristics such as limited geological knowledge, high exploration risk, difficult operating conditions such as very deep water, strong gales and currents, large waves, and lack of infrastructure. All characteristics apply to West of Scotland.
*Corresponding author. Tel.: +44-01224-272168; fax: +44-01224-272181. E-mail address: [email protected] (A.G. Kemp). 0278-4343/01/$ - see front matter # 2001 Published by Elsevier Science Ltd. PII: S 0 2 7 8 - 4 3 4 3 ( 0 0 ) 0 0 1 2 6 - 6
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To obtain a proper understanding of the economic aspects of oil and gas exploitation requires consideration of all these features. Further complications with respect to the West of Scotland region are (a) the highly variable water depths, and (b) the presence of several distinct geological basins. In addition some basins have been subject to a substantial amount of exploration while to date others have experienced little or none. This paper takes account of all these factors and provides an analysis of the prospective returns at (a) the exploration stage and (b) the field development stage. These are the key investment decision points in the decision-making process in the petroleum industry (Kemp and Stephen, 1998).
2. Methodology and data 2.1. Exploration The exploration prospects are assessed by the estimation of expected monetary values (EMVs) employing the Monte Carlo technique. EMVs highlight the risks and the range of possible outcomes from the exploration activity. Appraisal risk is included in the study to reflect the possibility that a discovery will be so small that its development is uneconomic even at ‘‘high’’ oil prices. The general form of the model is shown schematically in Fig. 1. The model postulates an exploration success rate, an appraisal success rate and a distribution of field sizes. This is lognormal, reflecting the general experience in all petroleum provinces. For discoveries made there is a range of field development costs and operating costs. The distributions for both of these are presumed to be normal. The UK oil price is also modelled as stochastic with normal distribution and time dependency characteristics. The distribution for each stochastic variable is defined by a specified mean and standard deviation. The study examines the different geological basins separately and estimates the EMVs for each. There are some common and some separate assumptions employed. The variations reflect the different known characteristics of each basin.
Fig. 1. Schematic P representation of investment situation facing explorationist. In the circumstances described above the i¼n EMV ¼ pcd i¼1 prob: NPVfl E psdA:
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Fig. 2. Development costs with mean values, standard deviation and minimum and maximum values. The standard deviation was set at 12.50% of the mean.
Common assumptions include a total exploration and appraisal cost of $60 million with $20 million being spent on exploration in 1998, $20 million on appraisal in the year 2000, a further $20 million in 2002 and any subsequent field development occurring immediately after this. In the first instance it is assumed that because of lack of nearby infrastructure, any reserves found could only be developed on a stand-alone basis, and that only an oil find of greater than 50 million barrels (mmbl) would be developed. Thus any oil field with reserves of less than 50 million barrels or a gas field of any size would not be developed. For purposes of this part of the study, field developments by FPSO are assumed. Development costs were with mean values, standard deviation and minimum and maximum values as in Fig. 2. Annual operating costs were modelled as a percentage of accumulated development costs. The mean value was 10%. The standard deviation was set at 12.5% of the mean. Minimum and maximum values were set at 10 and 14%, respectively, of accumulated investment costs. The oil price was set at $18 in the initial period corresponding to first exploration. The standard deviation was set at 10% of the mean value, but price behaviour through time was modelled as time-dependent thus permitting rising or falling trends. Minimum and maximum values were set at $5 and $35, respectively. Given the very considerable uncertainties two cases of reserves size distributions were examined, both are lognormal. The first has a mean value of 150 million barrels and the second 100 million barrels. The standard deviation is 75% of the mean value. Historical exploration experience in the different basins was employed to determine appropriate values for making future estimates. The Judd Basin has been the most intensively explored and prospective. Foinaven, Schiehallion, Loyal, Suilven, Alligin and Conival have all been discovered in this area. The overall exploration success rate has been 29%. If gas discoveries are excluded the success rate is 25%. Perhaps two-thirds of the oil discoveries can be regarded as potentially commercial. In the West Shetland Basin at least 34 exploration wells have been drilled. The Clair and Victory fields are located in this basin as is another gas find. An overall exploration success rate of 8.8% reflects the position to date, but for oil alone it is only 2.94%. In the Rona-Flett Basin there have been 21 known exploration wells to date. The Larkspur, Newton and Lister discoveries are in this area. This gives a success rate of 14.3%, but the oil exploration success rate falls to 4.8%. In the Faroes Basin 16 known exploration wells have been drilled. The Torridon and Laggan gas finds are in this area. In the West Hebrides Basin 6 exploration wells have been drilled without known success. In the Foula Basin one well has been drilled.
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2.2. Results The calculations were conducted under the assumptions for success rates discussed above plus some additional sensitivities. Summary results showing the mean EMVs at different discount rates where the mean reserves from discoveries are 150 million barrels are shown in Fig. 3. For the case where the mean size of discovery is 100 million barrels the results are shown in Fig. 4. It is seen that positive returns are in prospect in only a minority of cases. The Judd Basin is the most attractive when the historic exploration success rates are employed. Given that this basin is relatively well-explored, it is possible that prospectivity in the future may be less than to date. Thus the results are shown for the case where the exploration success rate fell to 10%. These generally pessimistic results relate to the mean expected returns. It may well be that explorationists are generally optimistic regarding the chances of discovery. The Monte
Fig. 3. Mean expected post-tax EMVs under different assumptions.
Fig. 4. Mean expected post-tax EMVs under different assumptions.
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Carlo techniques provide much more information in the possible range of prospective returns. The full distribution of returns for the Judd Basin are shown in Fig. 5 for the case where the mean size of discovery is 150 million barrels. For an explorationist who is an optimist even with the historic success rates, it is seen that the post-tax EMV could be very substantial. There is a 30% chance that it will exceed $27 million and a 20% chance that it will exceed $41 million. On the other hand there is a 40% chance that the EMV will be negative. There is a 68% chance that it is in the $17 million to +$50 million range. Where the mean size of discovery is 100 million barrels there is a 68% chance that the post-tax EMV will be in the $18 million to +$25 million range. In this case there is a 30% chance that the EMV will exceed $10 million and a 40% chance that it will be negative.
Fig. 5. Judd Sub Basin}Initial oil price $18/bl, mean reserves 150 mmbl.
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In the Solan Basin with the mean size of discovery at 100 million barrels and success rates based on historic performance there is a 30% chance that it will be positive, a 20% chance that it will exceed $5.5 million, and a 10% chance that it will exceed $15 million. There is a 68% chance that it will be between $16 million and +$9 million. In the West of Shetland Basin with 10% exploration success and mean size of discovery of 150 million barrels the expected returns at the 68% probability level are all negative. This finding was also present for the Rona-Flett Basin. These findings were on the basis of 10% real discount rate. For exploration West of Scotland higher rates can certainly be justified given the risks involved. The conclusions are thus that exploration in this part of the UKCS is certainly high risk and the chances of losses substantial.
3. Development economics } oil 3.1. Methodology and assumptions } general The development economics of oil discoveries are now discussed. There are various development concepts available, particularly (1) FPS0, (2) conventional fixed platform and (3) tension leg platform (TLP). From an economic viewpoint the choice depends on a number of factors. To date FPSOs have been employed. They have some perceived advantages with respect to flexibility and versatility. There are also problems with this technology. There may be capacity limits. Currently they can sustain production of at least 140,000 barrels/day, but much higher output levels could require processing facilities on a scale difficult to accommodate on the vessel. In this paper emphasis is given to the comparative costs of oil exploitation via the three development options. Generally there are some economies of scale with respect to all the schemes. The extent of these varies, however, with the constraints on FPSOs noted above being an example. The relative costs also depend on other factors particularly water depth. Broadly, when FPSOs and TLPs are employed development costs do not vary dramatically with water depth, though some increase can be expected. On the other hand costs of development with a conventional fixed platform vary very substantially with water depth. A further complication relates to operating costs. For developments employing FPSOs these are somewhat higher than for platforms. Of course, tariffs payable for tanker transportation add considerably to overall operating costs. In the present study tanker charges to Sullom Voe or Flotta are included in the operating costs relating to the FPSO option. Total annual operating costs are modelled to range from 9.5% of accumulated development costs on a field of 100 million barrels to 6% on a field of 600 million barrels. 3.2. Assumptions } Judd Basin Two detailed case studies were undertaken, namely relating to the Judd Basin and the West of Shetlands Basin. They were chosen because they are of most current interest and because they illustrate the importance of water depth in the comparative economics of developments. In the Judd Basin discoveries have been made in water depths in the range 350–600 m with distances
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from shore in the range 140–210 km. A development in 400 m of water and 180 km from shore was chosen for detailed analysis. At this water depth in terms of field development cost FPSOs should constitute the cheapest option for the likely sizes of field. Clearly there will be a considerable range of development costs for all options. A possible minimum for the FPSO option in this water depth (reflecting very favourable circumstances) could range from around $4 per barrel for a 400 million barrel field. For significantly larger fields 2 vessels might be required and the minimum for a field of 600 million barrels could be $2.25 per barrel. Minimum development costs with a platform development were estimated to range from around $7.9 per barrel for a field of 100 million barrels to $3.6 per barrel for a field of 400 million barrels and perhaps $2.8 per barrel for one of 600 million barrels. For fields with reserves exceeding 200 million barrels the TLP concept is cheaper than a conventional platform. Again these figures relate to situations where all the circumstances regarding the development proceed favourably. Pipeline costs are excluded from the above. These have been examined and two cases considered. The first relates to a medium-sized pipeline (1800 diameter) over 180 km with 25 km lying in relatively deep water. This pipeline (including tie-in costs) was estimated to cost $113 million. The second case is a large pipeline of 3000 diameter. This is deliberately over-sized to accommodate the possibility of future third-party tariffing. The estimated cost (including tie-in cost) was estimated at $243 million. When these costs are added to the field investment cost the minimum total development cost using the platform option for the 100 million barrel field is around $9.45 per barrel with the 1800 pipeline and $10.75 per barrel with the 3000 line. The corresponding figures for a 300 million barrel field are $4.63 and $5.1 per barrel. For a 600 million barrel field they are $2.96 and $3.2 per barrel. Operating costs are somewhat less with the platform option. On an annual basis these have been estimated at 7.5% of accumulated field development costs for the 100 million barrel field, 5.5% on the 300 million barrel field, and 4% on a 600 million barrel field. 3.3. Results } Judd Basin The returns to investors in the Judd Basin in a selection of fields are now examined. The returns are shown in terms of post-tax net present values (NPVs) at 10% real discount rate. Oil prices of $18 and $14 in real terms have been employed. In Figs. 6 and 7 such returns are shown for the 150 million barrel field. Under the $18 price it is seen that with the FPSO concept potential returns are significantly positive when development costs are in the range $3.5–$6.5 per barrel. A TLP development would not be possible except at the highest part of the cost range shown. Because of the lower operating costs such a development with the 1800 pipeline could produce an NPV at least as large as that with the FPSO. If a large pipeline were employed the NPV becomes negative. Under the $14 oil price the NPVs are substantially positive with FPSO developments when investment costs are $5 or less per barrel. At higher costs returns are negative. A TLP development would not be viable at all under this oil price. For fields significantly smaller than 150 million barrels it was found that only FPSOs offered the possibility of positive returns and then only in limited circumstances. The development of a 100
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Fig. 6. Post-tax RNPV at 10% Judd Basin, 150 mmbl field oil price $18.
Fig. 7. Post-tax RNPV at 10% Judd Basin, 150 mmbl field oil price $14.
million barrel field offered worthwhile returns under the $18 price with investment costs in the $4.5–$6.5 per barrel range. Under the $14 price returns were found to be positive only when development costs were $5 per barrel or less. Investment in a 200 million barrel field was found to produce substantially positive returns under the $18 price using FPSO technology when development costs were in the $3–$6.5 per barrel range. A TLP development with an 1800 pipeline could be viable if the total investment cost were in the $6–$7.20 range. In such cases the returns were found to be comparable to those with
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FPSO developments involving investment costs of $5.5–$6.5 per barrel. Under the $14 price only FPSO developments were found to offer positive returns and then only when investment costs were $5 per barrel or less. The returns to an investment in a 300 million barrel field are shown in Figs. 8 and 9. Under the $18 price using FPSO technology substantial returns are attainable with development costs in the $2.5–$6.5 per barrel range. On this size of field a TLP development with 1800 pipeline would produce worthwhile positive returns when total investment costs are in the $4.90–$6.90 per barrel range. In fact the returns would then be higher than those from a comparable FPSO development with field investment costs in the $4.50–$6.50 per barrel range. Under the $14 price returns to the investor are substantially positive using the FPSO option with field development costs of $5 per barrel or less. At higher unit investment costs the project’s economic viability becomes doubtful. It is noteworthy that at such levels of development costs the returns are generally higher with the TLP option, especially when the medium-sized pipeline is employed. The results for a field of 400 million barrels are shown in Figs. 10 and 11. Using the FPSO development concept returns to the investor under the $18 price are very substantially positive with development costs as high as $6.5 per barrel. When the TLP concept is employed it is seen that in the development cost range $4.50–$6.50, this alternative produces somewhat higher returns when the medium-sized pipeline is employed. Under the $14 price scenario returns to the investor are positive with FPSO technology when development costs are $5.50 per barrel or less. It is again noticeable that when development costs exceed $4.50 per barrel the TLP option with a medium-sized pipeline produces higher returns than the FPSO technology. At even higher levels of reserves the economic case for the TLP option becomes progressively stronger. Thus in cases of fields with 500 and 600 million barrels of reserves the unit cost of a TLP
Fig. 8. Post-tax RNPV at 10% Judd Basin, 300 mmbl field oil price $18.
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Fig. 9. Post-tax RNPV at 10% Judd Basin, 300 mmbl field oil price $14.
Fig. 10. Post-tax RNPV at 10% Judd Basin, 400 mmbl field oil price $18.
development became very competitive with that of the FPSO, and for most likely cost conditions the returns to the investor were greater. The general conclusion, however, is that for smaller and medium-sized field the FPSO option is likely to be the more economic option. Even for fields as large as 300 or 350 million barrels the FPSO option offers the prospect of higher returns because quite low-cost developments are possible with this technology.
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Fig. 11. Post-tax RNPV at 10% Judd Basin, 400 mmbl field oil price $14.
3.4. Assumptions } West Shetland Basin In the West Shetland Basin, where several discoveries including Clair and Victory have been made, the water depths are much less than in the Judd Basin. The known discoveries are in water depths in the range 125–385 m, 76–122 km from Shetland. For purposes of this study the development economics of a discovery in 150–200 m of water 80 km from shore are examined. In such conditions the cost advantages of the FPSO option are considerably reduced. In this water depth the minimum development cost under this option for a field of 100 million barrels could be around $3.50 per barrel, progressively falling to $2.60 with a field of 200 million barrels, $2.25 at 300 million and $2.0 at 400 million barrels. For this water depth a fixed conventional platform development is generally cheaper than the TLP concept. The minimum development cost with the 1800 pipeline is estimated at $4.0 per barrel for a field with reserves of 100 million barrels, $2.90 for a field with 200 million, $2.54 for 300 million, and $2.2 for a 400 million barrel one.
3.5. Results } West Shetland Basin The prospective returns to an investor in a field of 150 million barrels are shown in Figs. 12 and 13. Under the $18 price case the returns are positive with all development options for development costs as high as $6.90 per barrel. It is noteworthy that the returns are higher with the fixed platform option and the 1800 pipeline. This size of pipeline is also sufficiently large to permit thirdparty transportation from other fields. Under the $14 price scenario the returns to the investor are positive when development costs are $5 per barrel of less. It is again seen that the NPVs are higher with the platform option.
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Fig. 12. Post-tax RNPV at 10% West of Shetland Basin, 150 mmbl field oil price $18.
Fig. 13. Post-tax RNPV at 10% West of Shetland Basin, 150 mmbl field oil price $14.
The next case examined is a field with recoverable reserves of 200 million barrels. The returns to the investor are shown in Figs. 14 and 15. Under the $18 price the NPVs are all substantially positive under both development options. It is seen that the returns are generally higher with the platform development option and the 1800 pipeline. In some of the cost cases the combination of the platform with the 3000 pipeline is competitive with the FPSO option.
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Fig. 14. Post-tax RNPV at 10% West of Shetland Basin, 200 mmbl field oil price $18.
Fig. 15. Post-tax RNPV at 10% West of Shetland Basin, 200 mmbl field oil price $14.
Under the $14 price the project produces positive returns under both development options when development costs are $5 per barrel or less. Again the platform option with 1800 pipeline produces the higher NPVs. The next case is a field of 400 million barrels. The returns to the investor are shown in Figs. 16 and 17. Under the $18 price for the whole range of development costs shown the NPVs are very substantially positive under the different development options. The platform option generally produces the higher returns. On this field the investment in the larger pipeline is seen to produce higher returns than the FPSO option.
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Fig. 16. Post-tax RNPV at 10% West of Shetland Basin, 400 mmbl field oil price $18.
Fig. 17. Post-tax RNPV at 10% West of Shetland Basin, 400 mmbl field oil price $14.
Under the $14 price returns to the investor are positive with development costs as high as $.5.50 per barrel (plus pipeline costs). Again the platform option generally produces the higher returns. The general conclusion from this part of the study is that from an economic viewpoint a platform-based development is much more feasible in the West of Shetland Basin than was the case in the Judd Basin. Further, a conventional platform will generally have cost advantages over a TLP. The choice of option becomes more difficult on smaller fields where FPSOs sometimes
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have the cost advantage. On quite small fields (less than 100 million barrels) exploitation will be uneconomic by either development option even in this moderate water depth, especially under a $14 price. 3.6. Subsea development plus use of common infrastructure } assumptions In the North Sea many small fields are rendered economic via the use of existing infrastructure. Although very little infrastructure currently exists West of Scotland it is useful to consider such a future possibility. This provides some basis for the analysis of the future development economics of smaller fields. The hypothetical case examined is one where a field is developed with a subsea system tied back to an established facility which processes and exports the oil. The case of infrastructure comprising a platform and pipeline is considered but the basic ideas also apply to an FPSO and tanker transport. Two examples are examined when the distances between the subsea development and the host platform are 15 and 30 km. Tariffs for processing and transportation are set at £1 per barrel with a sensitivity case of £2 per barrel. The estimated minimum field investment costs for subsea development in West of Scotland conditions were set at $7 per barrel for a 25 million barrel field falling to $4.10 for one of 50 million barrels, and $2.8 for one of 100 million barrels. When the capital costs of a 25 km flowline are included the total minimum estimated development costs for the 3 cases increase to $7.52, $4.32 and $2.91 per barrel. If the flowline were 30 km the minimum investment costs for the 3 fields increase to $7.84, $4.48, and $3 per barrel. Annual operating costs are estimated at 8.5% of accumulated investment costs for the 25 and 50 million barrel fields and 7.5% for the 100 million barrel one. 3.7. Subsea developments with tie-ins } results The NPVs for the projects as described above were calculated. By way of comparison the returns to the projects are also shown when they were developed with stand-alone FPSOs and platform plus pipelines under West of Shetland conditions. It was found that the returns to the 25 million barrel field were negative. They are not shown here. The returns to the 50 million barrel project are shown in Figs. 18 and 19. Under the $18 price it is seen that when developed on a subsea basis the project offers positive returns when the tariff is £1 per barrel over a plausible range of development costs from $4.6to $6.5 per barrel. This remains the case when the distance from the platform is 30 km. When the tariff is £2 per barrel the returns remain positive over the same investment cost range under the low tariff. Under the high tariff the NPVs are negative at development costs of $6.5 per barrel. Returns are also positive for development via FPSOs and platforms in moderate water depths for development costs in the $5.5–$6.4 per barrel range. Under the $14 price scenario the picture is very different. The returns under most of the conditions examined are negative. Only under the lower levels of cost examines is the project viable.
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Fig. 18. Post-tax RNPV at 10% Subsea tie-in, 50 mmbl field oil price $18.
Fig. 19. Post-tax RNPV at 10% Subsea tie-in, 50 mmbl field oil price $14.
The results for the 100 million barrel project are shown in Figs. 20 and 21. Under the $18 price scenario the returns are positive under all the combinations examined for development costs as high as $6.5 per barrel. Under the $14 price case the returns under all combinations are positive with developments costs of $4.5 per barrel or less. At development costs of $5 per barrel the returns are positive in all cases except those with the high tariff. At development costs of $5.5 per barrel more returns are negative.
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Fig. 20. Post-tax RNPV at 10% Subsea tie-in, 100 mmbl field oil price $18.
Fig. 21. Post-tax RNPV at 10% Subsea tie-in, 100 mmbl field oil price $14.
The main conclusions of this section are that subsea development can render viable some fields which would otherwise have been uneconomic. It remains the case, however, that some projects which might well be viable in North Sea conditions would remain sub-economic in West of Shetland conditions. The size of the tariff payable can be important in determining the viability of some projects and in determining whether a subsea tie-in or stand-alone development is the more economic concept.
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4. Development economics } gas 4.1. Location and possible development/operating costs } general Gas has been discovered in several area West of Shetland. The Torridon and Laggan fields are in the Faroes Basin. The Larkspur, Newton and Lister discoveries are discoveries in the RonaFleet Basins. The Victory discovery is in the West Shetland Basin. The Conivial discovery is located in the Judd Basin. As was discussed for oil exploitation for water depths of less than 200 m or so a conventional platform development is generally cheaper than a TLP. In very deep waters the TLP becomes very much more economic. In this part of the study the cheaper investment option has been determined for the typical water depths in the different basins. The minimum possible investment costs have been estimated and a further case of this minimum plus 25% included in the analysis. Gas may be used in many ways. In this study the emphasis is on its possible use in the UK gas market in a conventional manner with pipeline transport. The general methodology employed was to calculate the possible combinations of reserves and gas prices required to permit the recovery of all investment costs plus a minimum return on that investment. This was set at 10% post-tax in real terms. 4.2. Judd Basin } assumptions In this basin cases of field developments in 500 m of water were examined. The TLP concept is clearly cheaper than a conventional platform in such conditions. The minimum field development cost (excluding pipelines) in this water depth was estimated at 17.3 pence per therm for a 300 bcf field, falling to 10.4 pence for one of 600 bcf, 7.3 pence for 1 tcf, and 4.7 pence for 2 tcf and still larger field. Pipeline costs (including tie-in costs) were estimated to (a) a landfall point in Orkney, (b) to the FLAGGS trunk line and (c) to the Frigg trunk line. These vary according to pipeline diameter. For a 2200 pipeline the cost to Orkney was estimated at $184 million, to FLAGGS $257 million, and to the Frigg line $295 million. For a 3200 line the corresponding costs were estimated at $267, $374, and $430 million. For a 4000 line the corresponding costs were set at $334, $468, and $539 million. Tariffs from these pipeline systems to the St. Fergus terminal were estimated at 40 pence per mcf in both cases. 4.3. Judd Basin } results The results for the case where the gas is landed in Orkney are shown in Fig. 22. It is seen that, depending on the investment cost the gas price necessary to recover costs plus a 10% return, ranges from 45–53 pence per therm for a 300 bcf field to 15–20 pence for fields in the 2–6 tcf range. It is likely that investors would require a higher expected return to compensate for the risks involved. There is currently no significant gas market in Orkney. The scenario where the gas is landed at St. Fergus is thus of more interest. The results for the case where the gas was linked into the FLAGS line and then taken to St. Fergus are shown in Fig. 23. The price required at St. Fergus
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Fig. 22. Judd Basin to Orkney (water depth 500 m, TLP).
Fig. 23. Judd Basin to FLAGS (water depth 500 m, TLP).
varies according to the investment cost from 32–37 pence for a 1 tcf field to 19–25 pence for very large fields. These figures relate to a relatively low return on capital in relation to the risks. The results for the route via the Frigg pipeline were not significantly different from the FLAGS case.
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4.4. Faroes Basin } assumptions The exercise was repeated for gas fields in the Faroes Basin. In this case Shetland is the nearest landfall. Water depth of 400 m was assumed. The estimated pipeline costs to Shetland and the FLAGS and Frigg pipelines for a 2200 line were estimated at $114, $238, and $286 million, respectively. For a 3200 line the costs were estimated at $164, $346, and $416 million. For a 4000 line they were estimated at $205, $433, and $521 million, respectively. The results for the case where the gas is landed in Shetland are shown in Fig. 24. Depending on the field investment cost the price necessary to recover costs plus a 10% return are in the 42–51 pence range for a 300 bcf field, falling to 15–21 pence for 2 tcf and larger fields. The results for the case where the gas is piped to the FLAGS line and then to St. Fergus are shown in Fig. 25. For a field of 1 tcf the required price is in the 31–37 pence range depending on the field investment cost. For a 2 tcf field the range is 22–24 pence. For still larger fields requiring more platforms the price range is similar. As before these prices should be regarded as minimum given the risks involved. An alternative development scheme when gas is found in very deep water would be to locate the platform in shallower water and produce the gas from a series of subsea systems tied back to the platform. The saving in platform costs could be very substantial, particularly if it were to be located in water depths of 200 m or less. This saving could readily more than compensate for the costs of subsea systems and the associated flowline costs. 4.5. Rona-Flett Basin } assumptions In this basin discoveries have been made in a variety of water depths ranging from over 300 m to under 100 m. Case studies were conducted of developments in water depths of (a) 500 m and (b)
Fig. 24. Faroes Basin to Shetland (water depth 500 m, TLP).
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Fig. 25. Faroes Basin to FLAGS (water depth 500 m, TLP).
150 m. Cases of pipeline transportation to Shetland, the FLAGS line and the Frigg Line were examined. For a 2200 pipeline in 150 m of water the costs were estimated at $204 million to FLAGGS and $295 million to the Frigg line. For a 3600 line the corresponding costs were $330 and $479 million, and for a 4000 line $371 and $538 million. These figures are relatively high because, although the field is in relatively shallow water, the location of these waters is such that the distance is considerably greater than from the deep water location. 4.6. Rona-Flett Basin } results When the field was located in 500 m of water it was found that the results were not substantially different from those for the Faroes Basin. The minimum price required is a little lower in the Rona-Flett case. The results for the case where the field is located in 150 m are shown in Figs. 26 and 27. Where the gas is delivered to Shetland it is seen that the minimum price falls from 22 to 26 pence per therm for small fields to 10–13 pence for very large developments. If the gas were transported to FLAGS and then to St. Fergus the minimum price falls from 20– 22 pence for a 1 tcf field to 14–18 pence for much larger scale developments. 4.7. West Shetland Basin } assumptions At least 2 gas discoveries have been made in this area including the Victor field. Typical water depths are in the 150–200 m range. A case of a field located in 200 m of water around 80 km from Shetland was examined. For a 2200 line the costs to Shetland are estimated at $83 $106 million to the FLAGS line and $163 million to the Frigg line. For a 3600 line the corresponding costs are $131, $169 and $263 million. For a 4000 line they are $147, $190, and $295 million.
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Fig. 26. Rona-Flett Basin to Shetland (water depth 500 m, TLP).
Fig. 27. Rona-Flett Basin to FLAGS (water depth 500 m, TLP).
4.8. West Shetland Basin } results The required minimum prices for landings in Shetland and St. Fergus are shown in Figs. 28 and 29. The minimum price required for gas landed in Shetland was found to range from 23 to 27 pence for a 300 bcf field, to 15–17 pence for a 1 tcf field, and 10–14 pence for much larger ones.
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Fig. 28. West of Shetland Basin to Shetland (water depth 200 m, conventional platform).
Fig. 29. West of Shetland Basin to FLAGS (water depth 200 m, conventional platform).
For landings at St. Fergus the minimum price was found to be in the 19–22 pence range for a 1 tcf field falling to 14–17 pence for much larger ones. 4.9. West Hebrides } assumptions Water depths to the west of the Hebrides are much greater than in the other areas examined. Distances to landfalls are also very long. A case where fields were discovered in water depths of
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Fig. 30. West Hebrides to Orkney (water depth 1500 m, TLP).
1500 m located 580 km from Orkney was examined. A TLP development concept was employed. The pipeline costs for delivery in Orkney were estimated at $580 million for the 2200 line, $938 million for the 3600 line and $1 billion for the 4000 one. The pipeline costs for deliver to Barrow for the same sizes of pipeline were estimated at $864 million, $1.4 billion, and $1.6 billion. 4.10. West Hebrides } results The minimum required prices for landing gas at the 2 destinations are shown in Figs. 30 and 31. For Orkney these range from 60 to 70 pence for a 300 bcf field to 37–42 pence for a 1 tcf development, and 20–26 pence for much larger fields. For landings at Barrow the minimum prices was found to be in the 42–50 pence range for a 1 tcf development, falling sharply to 22–28 pence for large fields with reserves of 3 tcf or more.
5. Conclusions This paper has examined the economic aspects of oil and gas exploration and development in some detail. There is a considerable exploration history in the region going as far back as the early 1970s. A substantial number of wells have been drilled although overall success rate has been quite low. In the period 1988–1998 inclusive it has been only 8.8% for the whole region. The region comprises several distinct geological basins (unlike the area East of Shetland, for example). The prospects for each of the main basins were examined separately. Based on historic success rates exploration in the Judd Basin offered the best economic prospects. In most basins the mean expected returns facing an explorationist were negative. The evidence supports the view that the West of Scotland region should be regarded as high risk.
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Fig. 31. West Hebrides to Barrow (water depth 1500 m, TLP).
At the field development phase the position in the West of Scotland region is made more complex by the presence of a wide range of water depths which complicate the choice of development concept. To date FPSOs have been employed in the relatively deep waters in the Judd Basin. In shallower waters, such as in the West Shetland Basins, conventional platforms could be more economic. In deep waters for large discoveries the TLP could constitute the most economic concept. Under an $18 constant real oil price medium and large oil fields with plausible development costs should be economically viable. The use of the FPSO concept should produce the highest returns on medium-sized fields, but in large fields the TLP concept may be more attractive in situations where development costs are relatively high under all development options. The viability of small field developments with reserves of 50 million barrels or less is more problematic. With a $14 price the picture is quite different. Only with relatively low or moderate development costs are projects likely to be viable on a stand-alone basis. In this context it is noteworthy that many companies are assessing new investment projects at this and even lower prices. Subsea tieins offer some scope for the development of some fields which are otherwise uneconomic. Several gas discoveries have been made West of Scotland. The potential economic viability of these was examined by calculating the minimum gas prices required to make economically viable various combinations of reserves and costs (field plus pipeline) in different locations. The required delivered prices at St. Fergus were relatively high. An interesting finding from the analysis of the investment cost structures was the relatively moderate share taken by very long pipelines even in deep water. Generally the implications of the study are that ‘‘higher’’ oil and gas prices and/or significant innovations and technological advances are required for fuller exploration and development. Higher prices certainly cannot be guaranteed. If the region’s potential is to be fully exploited
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development of new technologies and the wider diffusion of recent advances are likely to be necessary. References Kemp, A.G., Stephen, L., 1998. The Economics of Oil and Gas Exploration and Development. North Sea Study Occasional Paper No. 67. Department of Economics, University of Aberdeen,West of Scotland, September, 143pp.