Economic Report 2001 Index

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Industry Activity in 2001 Investment Climate Investor confidence which began returning to the UKCS in 2000 flowed through into 2001 with a notable increase in the number of fields being sanctioned - 21 fields compared with 10 in 2000 - and with sustained exploration, appraisal and in-fill drilling activity. These actions in combination with the continuation of fiscal stability have assisted in maintaining a positive investment climate for the UKCS and have helped sustain competitiveness in the face of the challenges engendered by maturity. The continuing PILOT agenda stimulated the creation of new work groups in 2001 to study Brown Field potential and exploration and industry processes. Proposals from these work groups are aimed at encouraging greater investment in mature acreage and undeveloped discoveries as well as facilitating easier asset trading. Risk taking is an inherent feature of the industry's business. Geological risks are defined by nature and price risks are subject to world market forces, so neither of these are controllable in the UKCS environment. However, regulatory risks are man-made, e.g., by Governments in both the UK and the European Union (EU). UKOOA has initiated a positive engagement programme with parliamentarians, regulators, legislators and officials to provide information about industry operations and capabilities to try to ensure that new regulations are appropriate for the offshore sector. Securing the industry's exemption from the Large Combustion Plant Directive has enhanced opportunities to maximise recovery of oil and gas from the UKCS. However, some uncertainty remains regarding further OSPAR regulation. Furthermore the impact of changes to the regulation and operation of the downstream sector can have implications for investment plans for further UKCS development. UKOOA and PILOT are working to find practical solutions to resolve current operational difficulties to enhance both upstream and downstream services. As the largest offshore industry in the EU, the UK has an important role to play in the supply of oil and gas. Policy proposals emanating from the EU's Security of Supply Green Paper and the UK's Performance and Innovation Unit's (PIU) Energy Policy Review are anticipated in 2002. These may have implications for future investment. UKOOA believes that it is important that any policy proposals that emanate from such deliberations do not compromise the upstream investment climate in the EU in general, or on the UKCS in particular. Oil Markets Oil price volatility continued in 2001. Although the average price for the year has been around $24.5/bbl, prices have fluctuated as the market reacts to short term concerns over the supply/demand balance. In the early part of the year prices peaked to just over $30/bbl following the first OPEC cut of 2001 and a more bullish view about the US economy. The lowest oil prices of the year were seen in mid-November when the price dipped below $17/bbl for the first time since June 1999 after OPEC made further cuts conditional upon "non-OPEC" support.   Figure 7: Dated Brent in 2001   On the supply side, OPEC continued to try to maintain prices within a target range of US$22/bbl to US$28/bbl for the basket of OPEC crudes (Brent equivalent around US$23.50/bbl to US$29.50/bbl). During 2001, OPEC ministers agreed to cut production four times (January, March, July and November), a cumulative cut of some 5 million barrels per day. Balancing these cuts, non-OPEC supply was expected to increase by between 0.75 and 1 million barrels per day following the reversal of the investment cutbacks after the collapse of oil prices in 1999.   Figure 8: Dated Brent and Rollin 3 Year Forward Prices   The fundamentals continue to suggest that the future outlook for prices is soft. For much of the year, the forward markets indicated a medium term view of prices around $19/bbl (2001 prices), although more recently these prices have dropped much closer to the $18 average seen since 1996. Figure 8 shows how the forward price for deliveries 3 years ahead has varied in comparison to the spot market. Volatility is greatly reduced, with prices being outside the $15 - $20 range only for short periods. For decision-making it is the perception of prices into the future that are important. For field developments the economically significant period is typically 2 -10 years into the future extending out to 5 -15 years away for new exploration activity. On the demand side, in light of the economic slowdown in the US and elsewhere compounded by the impact of the events of 11 September, the International Energy Agency (IEA) expects overall world demand to rise by only 0.2% in 2001 and by 0.7% in 2002. This compares with an average of 1.8% seen in the late 1990s. (See Table 1) Gas Markets Historically, in the UK, gas was regarded as a premium fuel and sold into the domestic, commercial and certain industrial markets. During the 1990s, market liberalisation combined with the economic and environmental benefits of gas-fired power generation caused rapid growth such that gas demand rose to over 9.3 billion cubic feet per day (bcfpd) in 2000.   Figure 9: UK Gas Demand by Sector   Gas production in 2001 is estimated to be around the record of 10.5 bcfpd reached in 2000. In 2000 gas represented almost 44% of UKCS annual hydrocarbon production and some 36% of UK energy production. With a share of 4.5% of world production, the UK was the fourth largest gas producer and has continued to be a net exporter of gas, exporting some 390 bcf to Europe. Unlike oil, the majority of UKCS gas produced for the UK market is sold under long and medium term contracts indexed to, but lagging, a variety of factors such as inflation and energy prices. The remainder is sold directly into the wholesale spot market. Since the mid-1980s the real price of gas supplied by UKCS producers at UK delivery points has more than halved. Whilst there are a variety of contract prices they tend to be lower than the spot price which averaged 22p/therm in 2001, still lower than oil's value in equivalent terms, despite the relative environmental premium associated with gas. Figure 10 shows gas prices as the competitive gas market developed. In 1995 UK gas began to be traded on the spot market. Prices paid by manufacturing industry and other end-users are higher than the prices received by producers, reflecting the shippers' transportation, overhead and distribution costs, plus a small margin.   Figure 10: Development of the Competitive as Market - Gas Prices Since 1980, in Real Terms   The European gas Interconnector pipeline between Bacton and Zeebrugge was opened in 1998 and allows gas to flow to or from the European market. The facility has an export capacity of 2 bcfpd, or about 15% of the UK's peak demand. At present a smaller volume of gas (0.8 bcfpd) can flow into the UK, although the Interconnector is currently considering upgrading import capacity to potentially higher volumes than the existing export level. Figure 11 indicates that export gas has predominated in 2001, especially in the summer months. Later in this decade, if UK gas supplies begin to decline as forecast, gas imports through the Interconnector can be expected to rise.   Figure 11: Net Monthly Interconnector (Bacton-Zeebrugge) Gas, 2001   Figure 12 illustrates the movement in fuel prices paid by UK industry since 1988. Until the year 2001 gas prices had fallen in real terms more than any other fuel. The recent price rise has chiefly been due to the increase in the global oil price and the influence of oil-indexed continental gas prices on those of the UK, via the Interconnector. During 2001 prices softened in response to the decline in oil prices from $30 to under $17/bbl. However, the price benefit to industrial consumers will be offset by the impact of the 4.4p/therm Climate Change Levy which significantly increased gas prices from April 2001. Not surprisingly the fall in gas prices through the 1990s encouraged a rapid growth in demand driven largely by the growth in gas-fired electricity generation. This doubling in gas demand was almost exclusively met by UKCS supplies at a time when field sizes, as a well as prices, were falling.   Figure 12: UK Real Fuel Price Indices for the Industrial Sector, 1998 - 2001   Box 4: What Influences Gas Prices in the UK In 2001 ILEX (independent consultants) were commissioned by UKOOA to examine the cause for the rise in gas prices during 2000. They concluded that "The link with oil indexed gas prices on the Continent is the most important factor in explaining the rise in UK gas prices through 2000." UKOOA's View on other factors affecting UK gas prices: Auctions of NTS entry capacity by Transco have dramatically increased the cost of entry capacity at most terminals - for example the cost of landing gas at St Fergus was 0.64p/therm in 1998/99, but was an average of 6.1p/therm in the summer of 2001. The gas industry is facing continual changes arising from regulatory direction under the Reform of Gas Trading Arrangements. This has led to a great deal of uncertainty within the industry and has had a knock-on effect on prices. Demand for gas in the UK has increased by 66% since 1992: this has meant a tightening in the UK supply/demand gap which will continue as the UK moves towards becoming a net importer of gas. This has led to upward pressure on prices. Exploration Exploration and appraisal drilling in 2001 is expected to have been similar to the number of wells drilled in 2000 (59 wells).   Figure 13: Exploration and Appraisal Activity in the UK Sector, 1999 - 2001   Exploration spending, including geological and geophysical work as well as drilling, but excluding in-field exploration, is expected to be some £0.4 billion compared with £0.35 billion in 2000. Much of this increase is cost-driven as rig rates recovered from their low level in 1999. Typical costs for jack-ups and semi-submersible rig costs rose by 30% to 60% and are in the range $75,000 to $90,000 per day. This excludes the cost of support vessels and tangible materials such as the steel and valves needed in the wells. Specialised rigs can command a premium of some 50%. The outlook for 2002 depends on a combination of factors. These include containment of the high cost of drilling, increased success in exploration West of Shetland following the Faroes discovery in November 2001, avoidance of an oil price collapse, improved economics for the smaller North Sea prospects and continued Government support in maintaining industry confidence. Development Activity The year 2001 was successful in terms of new developments on the UKCS with some 21 oil and gas projects including 1 redevelopment, having secured Annex B approval (DTI project approval), and a further 7 incremental projects (see Table 2). These projects alone are expected to cost some £2.5 billion to develop and yield some 0.9 billion boe. In particular, two of the basin's most intractable and challenging projects, Clair and Penguins were sanctioned. Both of these fields were discovered in the 1970s and have taxed the ingenuity of the owners over the years to develop innovative commercial and technical solutions to overcome the many barriers to development. New technologies have now helped forge economic solutions. In the case of Penguins, a new record will be established with a sub-sea tie-back distance of 65 kms to the host installation, whilst Clair will add significantly to the emerging infrastructure West of Shetland and extend the life of the Sullom Voe Oil Terminal. Technology has also helped accelerate development of other remote satellite projects such as Otter and Nuggets which gives encouragement that the many undeveloped discoveries on the UKCS whose progress has been frustrated by seemingly impossible technical barriers and large distance from infrastructure may yet be candidates for development.   Figure 14: Comparing Forties and Clair     Figure 15: Penguins: 65km Tie-back to Brent   During April 2001 the Elgin and Franklin fields came on stream. This is one of the largest developments of recent years and already they are the largest producers on the UKCS, delivering in excess of some 220 thousand barrels of oil equivalent per day.