Economic Report 2001 Index

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Meeting the Challenge Investment Intentions The industry and DTI have again co-operated on a joint survey of UKCS forward activity. The survey is based on a detailed assessment of the investment intentions of all UKCS operators in the summer of 2001. It is important to recognise that at that time the oil price was around $25/bbl. If the fall in the oil price to under $17/bbl, as seen in November 2001, were to be sustained through 2002 it is likely that the industry will experience difficulty in delivering the near-term aggregate investment levels indicated in the survey. The pie-chart in Figure 16 summarises the capital expenditure (capex) projection in the period 2002 to 2006 by probability category. Nearly half of the expenditure is in Sanctioned and Incremental projects, associated with fields in production or under development. Expenditure in Probable fields represents the largest category at some £6 billion. Over the 5 year period to 2006 the average annual spend is in excess of £3 billion, giving confidence that industry targets on expenditure can be met. However, the fact that only 25% of the projected expenditure has been sanctioned illustrates the fragility of the projections and their vulnerability to adverse changes to the investment climate. Based on the survey UKOOA predicts that development spending in 2002 will be similar to that of 2001, in the range of £3.3 to £3.8 billion.   Figure 16: UKCS Capex Forecasts, 2002 - 2006     Figure 17: UKCS Capital Expenditure Projections   Overall, the activity survey indicates that projects exist which could increase remaining basin expenditure in the period 2002 to 2006 by over £5 billion, compared to the year 2000 survey. Whilst this increase in activity potential is encouraging it will not deliver any increase in production over the previous year's predictions. In the past UKOOA surveys have generally indicated increased future production, hand in hand with higher investment. For example, the survey in 2000 indicated increased remaining reserve potential of over 1.5 billion boe. The current survey reveals a deterioration in basin economics and signals that previous surveys may have underestimated the remaining capex required to deliver underlying production profiles. The rapid decline in expenditure projected from 2004 onwards is not unexpected and is a consequence of the focussed planning horizon of operators' expenditure. This is likely to rise in the later years once they fall within the typical 5 year capital-planning horizon adopted by most operators. UKCS Reserves Up to the end of 2001 some 29 billion boe had been produced from the UKCS. The record production of the last few years is steadily depleting the remaining reserve base by some 1.6 billion boe per annum. This rate of extraction is now considerably in excess of the annual additions from new developments and discoveries. With as much production volume still ahead of us as has been produced to date we look to be around the half-way mark. Figure 18 summarises UKOOA's estimate of remaining reserves which is in the range 26 to 34 billion boe at the beginning of 2002. There is a large element of uncertainty associated with these estimates, in particular the undiscovered potential or Yet To Find (YTF) in undrilled prospects. UKOOA believes a range of 5 to 11 billion boe is an appropriate and realistic estimate. For these estimates to be meaningful it is important to articulate likely drilling activity and associated commercial success necessary to convert the potential to actual production. With the average size of new discoveries around 25 million boe it will take a significant and sustained increase in exploration drilling activity and subsequent development activity to convert this YTF potential to production. In the last 5 years, annual average reserve additions have been under 250 million boe. If this discovery trend is sustained, which will be difficult in a mature basin, then by 2020 UKOOA estimates that the discovered volumes are unlikely to exceed 5 billion boe. Much of the YTF will remain to be explored.   Figure 18: UKCS Remaining Oil and Gas Reserves Boe (from 1/1/2002)   Significant potential also remains in the categories of discovered reserves, classified according to the probability of the resource being developed. Probable fields are those likely to be developed within 5 years, whilst Possible fields have more uncertainty with respect to the prospects for development and may need new technology to permit economic development. Technical fields are deemed to be of a higher risk and at this stage are not thought of as development propositions. Many are very small in size (below 10 million boe), have difficult reservoirs (e.g.: shallow, fractured, low permeability or heavy oil) and are possibly remote from infrastructure. However new technologies could convert these to production during the remaining life of the basin. In the near term, a large reserve prize remains in 'Brown Fields', by increasing the recovery in existing fields in production or under development. UKOOA believes continuing work in this sector, with facilitation of best practices and benchmarking field performance, may be expected to reveal a potential of 2-4 billion boe, with anticipated improvements in new technology, provided the economic environment is favourable. Exploration Exploration remains the major potential source of future reserve development. Figure 13 illustrates that 2001 exploration activity has sustained the modest recovery seen in 2000. However, the economic fundamentals of UKCS exploration activity are well illustrated by Figures 19 and 20. Figure 19 illustrates how the average size of new discoveries has been steadily falling since the early 1980s, with the average field size over the last 5 years being some 25 million boe. This is a typical feature of all hydrocarbon provinces, as the largest and best prospects are drilled first. Obviously, this declining field size impacts the reserves added each year to the UKCS discovered resource base. Figure 20 shows the reserves discovered each year as a function of the number of exploration wells drilled. It can be seen that over the past 15 years, an average of around 10 million boe per well has been discovered (taking account of unsuccessful wells) as represented by the dotted red line. It is noticeable however, that the success rate in most years in the past decade has been less than 10 million boe per well. Largely as a result of the Buzzard discovery, 2001 looks like a relatively successful year.   Figure 19: UKCS Declining Discovery Size, 1965 - 2001     Figure 20: UKCS Exploration Discovery Rates   Box 5: Full Cycle Economics The true profitability of the UKCS is frequently overstated because of the tendency to ignore the research and development of the oil industry, namely the cost of exploration, both the successful and the dry well costs. An evaluation that incorporates all the costs associated with North Sea activity is referred to as 'Full Cycle Economics'. In a study by Wood Mackenzie, all exploration costs incurred in the period 1996-99 were aggregated with the projected cashflow from all the developments ensuing from discoveries made by that exploration effort. Figure 21 illustrates the results of this analysis. Based on those discoveries which Wood Mackenzie assess to be commercial and likely to be developed in the next 3-5 years, the analysis indicates a nominal return of around 2% at an assumed oil price of $15/bbl, and 8% at $20/bbl. However almost half of the reserves discovered from 1996 to 1999 were assessed by Wood Mackenzie to be non-commercial (referred to as 'Technical Reserves') due to their small size or remoteness from infrastructure. If all these technical reserves could become commercial with costs comparable to recent developments on the UKCS ($4/bbl), returns could approach more respectable levels. However this is an extreme assumption. More realistically, given a reasonable degree of success in the various industry initiatives, returns in the range 3-4% at $15/bbl, and 9-10% for a long term price of $20/bbl, could be expected.   Figure 21: Full Cycle Economics   The significance of the potential contribution of technical reserves is clear, and confirms the wisdom of PILOT focussing its efforts on commercialising undeveloped discoveries and lowering extraction costs. Similar conclusions have been reported in a more recent study undertaken by Alex Kemp, Professor of Petroleum Economics at the University of Aberdeen. Both studies emphasise the fact that the economics of UKCS exploration are highly fragile. Continued economic success depends on further breakthrough both in terms of reducing the cost of exploration and developing the technology to commercialise the small discoveries that characterise the UKCS today. International Comparisons In recent years the industry worldwide has gained access to previously inaccessible regions and unexplored provinces with notable successes, making large discoveries in deep water provinces such as Angola, the Gulf of Mexico and the Former Soviet Union (FSU). Wood Mackenzie maintains a database covering most regions of the world, and the database enables an objective assessment of the UKCS position against a wide range of provinces currently competing for investment funds. International comparisons of some of the key metrics are shown in Figures 22-25. Discovery Size: The analysis from Wood Mackenzie illustrated in Figure 22 demonstrates that the typical UKCS discovery is some 25-30 million boe, significantly less than the scale of discovery volumes available in Norway, Angola and the Gulf of Mexico. It is apparent from these metrics that what sustains the interest for all UKCS participants and prospective entrants is the prospect of 'value rather than volume', together with ready access to a skilled workforce and resources.   Figure 22: Discovery Size   Development and Operating Costs: The combination of small discovery and development volumes and the harsh operating environment of the North Sea engenders high development and operating costs/boe. The UKCS at $4/boe has the highest average development costs of all the provinces illustrated in Figure 23. Similarly, at over $4/boe the ongoing cost of UKCS operations is the highest amongst competing provinces (Figure 24). Failure to achieve cost reductions may jeopardise the viability of new developments in the face of competitive pressures, and undermine the economic justification for further exploration effort. However, one key advantage that the UKCS has over many of these provinces is an extensive infrastructure which fosters swifter development cycles and lower cost access for new fields in the catchment area. Achieving these lower costs for ongoing operations will extend the lives of producing fields on the UKCS.   Figure 23: Development Costs $/boe     Figure 24: Average Operating Costs $/boe   Maturity: Although the UKCS still has significant remaining reserves the industry faces some specific challenges related to the relative maturity of the UKCS as a hydrocarbon province. Figure 25 shows the relative maturity of a number of hydrocarbon basins by depicting the percentage of reserves discovered in the last five years on the vertical axis, against the percentage of historic production of proven reserves on the horizontal axis. The relative maturity of the UKCS compared to other basins is clear. On a different dimension Figure 26 represents the maturity status of the 10 largest oil fields on the UKCS. With the exception of Schiehallion, a comparatively recent development, these large oil fields are now heavily depleted with remaining reserves well under 10% of the total amount recoverable. Also the current production rates are generally low, typically below 50 thousand bpd.   Figure 25: Discovered Reserves     Figures 26: Depletion of UKCS Largest Oil Fields as of January 2001   The remaining UKCS hydrocarbon potential needs to be developed within a distinct window of opportunity posed by the gradual closing down of the existing UKCS infrastructure. Figure 27 indicates the potential reduction in acreage within reach of remaining producing infrastructure, as production from older fields declines to become uneconomic.   Figure 27: Window of Opportunity for UKCS Infrastructure   PILOT has targeted commercialising the remaining potential by accelerating the development of existing discoveries, stimulating exploration, and encouraging Brown Field development to extend the life of key infrastructure. Economies of scale: Another dimension of maturity to consider is the actual production being delivered by individual fields. The sequence of graphs shown in the Figure 28 illustrates how the portfolio composition of the UKCS oil fields has undergone, and continues to undergo, rapid change. In the mid-1980s the UKCS produced some 2.4 million bpd of oil from 27 fields, the largest fields produced nearly 500 thousand bpd and the 10 largest producing fields accounted for nearly 80% of total production. By year 2000 UKCS oil production was slightly higher, but required nearly 5 times as many fields to deliver it. Also the largest producing fields were much smaller, with only one field producing more than 100 thousand bpd, and the top 10 fields accounting for only 30% of production. This trend is expected to continue as fields mature and average production rates continue to decline. From an economic perspective this is far from ideal, as it is increasingly costly, per barrel, to produce from fields with relatively small production rates. By 2010 most, if not all, UKCS fields will produce less than 50 thousand bpd from ageing facilities that were designed for much higher production rates, creating the legacy of large fixed costs that are difficult to reduce as production declines.   Figure 28: Declining Economies of Scale - Contribution from Top Ten Oil Fields   New Entrants: The UKCS continues to attract independent oil and gas companies. The liquidity of the UKCS asset trading market highlights the ease with which participants choose to enter or leave depending on the competitive standing of the UKCS. Recent studies confirmed that the UKCS has two to three times as many participants (currently 70) as do Norway, Angola or deep water Gulf of Mexico. The independent companies play a vital role in ensuring that activity is optimised by building and exploiting niche positions such as in the management of mature fields and targeted exploration. Globally the competition to attract new entrants continues to intensify. The UK authorities need to remain vigilant in ensuring that the UKCS continues to be attractive for new entrants. Decommissioning UKOOA/DTI's 2001 activity survey has given further insights into the trends in decommissioning costs, the pace of removal and the changes over the last 2 years. Figure 29 illustrates the cumulative decommissioning cost expenditure for the UKCS as estimated in the last three industry surveys. The encouraging slippage in removal expenditure recorded in the year 2000 survey has not been repeated. If anything the expenditure has come forward though the estimated aggregate spend to remove infrastructure is unchanged at around £8 billion. At this stage of basin maturity, where relatively few platforms have been removed significant uncertainty remains as to the actual scope and cost of specific platform decommissioning. It is expected that removal costs will stabilise and possibly decline once the industry has gained more experience. This depends to a significant extent on changes to regulations governing decommissioning requirements. It will probably be at least 5-10 years before the experience of removing large structures from the Northern North Sea will give a real degree of certainty. However, in 2001 the Maureen installation was successfully removed from the UKCS to a safe location in a Norwegian fjord pending subsequent decommissioning and recycling. It has also been recently announced that the Hutton field will be decommissioned, having ceased production. Whilst DTI guidelines have been published there is still some uncertainty as to the required scope of any field removal.   Figure 29: Removal Cost Comparisons (2001 Prices)   Gas Figure 30 shows the potential gas production from the UKOOA activity survey and compares this potential with current UK demand. Since the projection excludes any contribution from exploration efforts it is likely that the inclusion of new developments from exploration success will sustain self-sufficiency until around 2005. It is also unlikely that the decline from this date will be as steep as the illustration represents since new projects will emerge as the planning horizon is extended.   Figure 30: UKCS Gas Production   Energy policy and regulation will also influence supply and demand and will help to determine when the UK will become a net importer of gas. The Government's announcement in November 2000 of the removal of the Stricter Consents Policy in respect of gas-fired power generation represented an important signal and step towards the restoration of investor confidence. Since then, the industry has responded to the DTI's consultation on the voluntary Code of Practice for third party access to offshore infrastructure, and is currently engaged in further consultation on the need for additional information about the operation of the gas market and gas prices. The regulatory regime downstream also impacts on what will be achieved upstream to extend UK self-sufficiency. There has been concern in 2001 over the National Transmission System (NTS) entry capacity auctions and the impact of imposing shorter balancing periods. As explained in its submission to the Energy Policy Review, UKOOA believes regulatory uncertainty can be a key inhibitor to maximising recovery of UKCS reserves. UKOOA has indicated that the current capacity regime is not working in the wider national interest, as it provides neither the investment signals to Transco, nor the certainty for producers. It is vitally important that there is sufficient investment in the NTS. There is a risk that complex technological achievements and advances offshore could be stalled simply through a lack of pipeline capacity onshore. Energy Policy Review UKOOA welcomed the UK Energy Review, published in February 2002. The industry acknowledges the importance of maximising the potential of current and future energy supplies for the UK. One of the key issues concerning policy makers is the prospects for UKCS gas supplies and the likelihood that imports will be required within the next 10 years. Gas is increasingly the fuel of choice as we move towards a lower carbon economy. Demand for gas in the UK almost doubled in the 1990s and continued growth in demand is forecast on the back of further market penetration by gas-fired electricity generation and the decline in the contribution from nuclear generation. Critical to the issue of security of supply is the contribution from domestic UK gas reserves and sources for imports once these become inevitable. Figure 31 indicates the status of UKCS gas resources at the end of 2001. Much depends on the Yet To Find or undiscovered potential of the UKCS with significant volumes ascribed to West of Shetland (WOS). If these volumes are to be commercial a combination of large individual discoveries, sustained higher gas prices, new technology and the ability to gain low cost access to the NTS (preferably at St Fergus), will be required. More exploration activity West of Shetland will ascertain whether this potential can be fulfilled.   Figure 31: UKCS Gas Reserves from 1/1/2002   In the longer term, Europe and the UK are well placed to import gas from many diverse sources. It has been estimated that some 70% of global proved gas reserves (5300 tcf) lie within economic transportation distance of the EU. As long as there is reasonable access to European pipeline infrastructure and investment and regulation will support the development of new infrastructure, reserves required to meet UK demand can be obtained. Figure 32 summarises some of the reserves that could be accessed.   Figure 32: Europe "Surrounded by a Sea of Gas"   The Future The recent industry activity survey for 2001 reveals a large number of investment opportunities that remain on the UKCS. Indeed compared to the previous year there has been a significant increase, some 27 fields, in the number of Probable and Possible fields that could be developed. Figure 33 illustrates UKOOA's best estimate of forward production from the UKCS. Also included on the chart are the PILOT Vision for 2010 (3 million boepd) and the Intermediate Target for production in 2005. The target for 2005 (4 million boepd) should be judged in the context of the production that is necessary to ensure that the industry is on track to meet the Vision for 2010. As the graph indicates the 2005 target will be challenging, requiring the development of all the Incremental and Probable fields. In effect, the industry needs to work hard so that between now and 2005 production on the UKCS remains more or less constant. This is a considerable challenge given annual production of 4.3 million boepd. UKOOA believes that the 2010 Vision can be delivered if the essential ingredients for success on the UKCS remain in place. These are: A shared agenda for the future and commitment to delivery from industry/Government/contractors and unions via PILOT. An attractive fiscal regime and appropriate regulation to sustain the competitiveness of the UKCS. The successful application of new technology. Avoidance of prolonged periods of oil price weakness. Further progress in streamlining business processes. Free markets that encourage enterprise, innovation, entrepreneurial activity and new entrants onto the UKCS.   Figure 33: UKCS Production Forecast