Alexander Kemp, Professor, University of Aberdeen
The year 2009 has been a difficult one for stakeholders in the UK Continental Shelf. The collapse in oil and then gas prices in the later part of 2008 was reflected in greatly reduced cash flows and subsequently in oil company budget cuts for 2009. The current year has, thus, experienced a major reduction in exploration in particular, though drops have also been recorded for appraisal and development drilling. In the first nine months of the year, exploration drilling amounted to 17 wells, compared with 37 in the same period of 2008. The corresponding numbers of appraisal wells are 39 and 49, respectively. The first nine months of 2009 saw 104 development wells drilled, compared with 128 in that period in 2008.
It is noteworthy, however, that activity did generally pick up as the year progressed. The increase in oil prices played some role in this. But wholesale gas prices have remained relatively low, and this has clearly affected investment incentives in gas-prone areas.
As a mature petroleum province located in a difficult operating environment, a province that also faces declining production and smaller sizes of new fields, there is much interest in reducing investment and operating costs. These have remained stubbornly high this year despite various initiatives being taken to reduce them. In the central North Sea, where much of the activity is based, the average development cost of a new field is nearly $19 per bbl of oil equivalent (boe). The average size of a new field is about 25 million boe. Total lifetime field costs (excluding exploration and appraisal) are over $32/boe. In the southern North Sea, where the water is relatively shallow but the average new field size is only 9 million boe, the development cost averages about $14/boe and total field lifetime costs average over $23/boe.
In such an investment environment, the materiality of returns in the UKCS relative to other regions has become an issue in the ongoing debate with the UK government on the effects of the tax system. For several years, there has been a formalized consultation between the industry and government on this subject. This resulted in the introduction of a field allowance against the Supplementary Charge (currently at 20%) in Finance Act 2009. For small fields, this totals £75 million with a maximum annual amount of £15 million. For qualifying very heavy oil fields and very high-pressure/high-temperature fields, the allowance totals £800 million, with the maximum annual amount being £160 million. The allowance should produce a modest but worthwhile stimulus to activity. I have estimated that at a $60/bbl oil price there could be 50 new field developments in the long term with additional total production of about 500 million boe.
The debate on the tax system is continuing, with a main subject being the position of mature fields currently subject to a total tax rate of 75%. To maximize economic recovery, incremental investments in mature fields are essential, and there is evidence that some are being inhibited by the 75% rate. It is likely that the debate will continue into 2010, when there will be the additional complication of a possible change of government.
In recognition of the cash flow problems posed by the fall of oil and gas prices and the world financial crisis, the government decided in early 2009 to postpone the launch of the 26th License Round. This is now expected to take place in early 2010. In general, it has been government policy to have annual rounds with the aim of maximizing exploration activity. A scheme involving a mixture of conventional, frontier and promote licenses has been employed for several years, and it is expected that this will continue. Policy has been to encourage all types of investors to apply, including very small companies, which receive a 90% discount on license fees for the first two years of a promote license.
Making projections of investment for 2010 is particularly hazardous. My economic modeling indicates that, if a conservative price of $45/bbl were employed to screen projects, investment would fall off dramatically from recent levels. If a $60 price were employed, investment could hold up at about recent levels. But if the effect of capital rationing were relatively strong, investment could fall, even if a $60 price were used for screening purposes. The increase in oil prices over recent months has been sustained, and this may encourage some investors. On the other hand, wholesale natural gas prices have remained low with no indication of a major change in the near term. In this context it should be noted that natural gas accounts for well over 40% of total hydrocarbon production from the UKCS.
Low gas prices have adversely affected the economics of developments in the West of Shetland region. There are considerable numbers of undeveloped gas fields in the region, but the very high investment costs and the absence of transport infrastructure have held back developments. To maximize economic recovery, a cluster-type development with a common processing hub and pipeline infrastructure has obvious merits. But, given the scattered location of the fields, their different stages in the exploration-appraisal-development sequence, and the substantial numbers of licensees involved, a collaborative scheme with a common infrastructure is very difficult to achieve. In recent months, new grounds for optimism have emerged in the shape of exploration/appraisal successes in the Glenlivet, Tornado, Tormore and Tobermory fields/prospects. There are hopes that development of the Laggan-Tormore complex will become a reality in 2010.
At the political level, there is the prospect of a Conservative government after the general election, widely anticipated to take place in May 2010. It is understood that a full review of licensing and taxation policy is being undertaken by a former energy minister. At the very least, this means that the debate on policy will continue with an additional dimension added. It could even be that a new, incoming government will decide to have an early budget. In any case, it is not clear if the present government will have been able to enact its budget proposals, currently expected to be announced in March.
Uncertainties for the UKCS thus abound. But the long-term potential remains substantial. Modeling that I’ve recently conducted suggests that, in the period 2009–2040, 18–20 billion boe could be produced given appropriate policies and incentives. 
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THE AUTHOR
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Alexander G. Kemp is the Schlumberger Professor of Petroleum Economics at the University of Aberdeen. He previously worked for Shell, the University of Strathclyde and the University of Nairobi. For many years, Professor Kemp has specialized in petroleum economics research, with emphasis on licensing and taxation. He also is Director of Aberdeen University Petroleum and Economic Consultants.
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