UK affected by market, regulatory uncertainties

Although the uncertainty of the Labour government’s fiscal review has been eliminated in the short term, other market and regulatory concerns persist. Operating conditions on the UKCS remain difficult during this period of low oil prices

Professor Alexander G. Kemp, University of Aberdeen, Aberdeen, Scotland

he year 1998 has been one of considerable uncertainty for investors on the UK Continental Shelf. As in other producing provinces, the price collapse has had a dramatic effect on industry cash flows. In turn, this has had a rapid and serious effect on exploration and appraisal work.

For the first six months of the year, these activities are down nearly 36%, in volume terms, compared to the same period in 1997. One can expect that this substantial fall will be sustained in the second half of the year. It is likely that when existing drilling rig contracts expire, not all will be renewed.

Aggregate field development activity has held up well this year. To a large extent, this is because investment commitments had been made already, before the oil price collapse. This year has seen the completion of several large projects, such as Britannia and Schiehallion. It has become clear that the next set of new developments is generally smaller in scale, with considerably less expenditure required.

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Tax Considerations

The year has been notable for other reasons. Continuation of the British government’s North Sea tax review, which was initiated in July 1997, meant that the investment uncertainty on that account was extended until September. At that point, it was announced that, due to the collapse in oil prices, no changes were being proposed in the short term.

The North Sea fiscal system is complex, with different arrangements applying to fields of different vintages, depending upon when they received development approval. Regarding the earliest generation of fields, defined as those developed prior to March 1982 (such as Forties, Brent, Ninian and Piper), royalty, Petroleum Revenue Tax (PRT) and corporation tax are all payable. This produces an overall top marginal rate of nearly 70%. For fields developed between 1982 and 1993, PRT and corporation tax are payable. For fields developed after March 1993, only corporation tax is due.

It was the category of new fields that gained the greatest focus of attention in the government’s review. In the debate, various arguments were produced to justify some tax increase. One argument related to international comparisons with other oil-producing countries, such as Norway. The tax take on new fields in that country is much higher, with a top marginal rate of 78%.

Great care should be taken in making cross-country comparisons. In Norway, overall geological prospectivity is higher, and the average expected size of discoveries is much larger. In the UK sector, the significant discovery rate has fallen somewhat over the last few years. In the 1995–1997 period, it averaged 12.8%. This compares with an 18.9% average over the 1988–1997 period, and 22.3% from 1984 through 1994. The average discovery size is now around 40 million bbl.

Not only are expectations regarding prospectivity significantly higher in Norway, there also is not such a perceived need to encourage investment in smaller, less profitable fields. Production has risen substantially through development of a moderate number of large and medium-sized fields to such an extent that the Norwegian government has felt inclined to restrain the pace of new development.

In the UK, the situation is quite different. The ratio of proven oil reserves to production (R:P) is around only 5:4. It is clear that, to prevent production from falling sharply in just a few years, the momentum of exploration, appraisal and development activity has to be maintained.

A further argument employed in the tax debate has related to success of the cost-reducing initiative (CRINE) in reducing investment and operating costs, thus increasing profitability and taxable capacity. This initiative certainly has been successful. According to official Department of Trade and Industry data, lifetime oil field costs, including 10% cost of capital, have fallen from an average $22/bbl for fields commencing production in the 1986–1998 period. They fell to $14.80/bbl for fields going onstream in the 1991–1993 period, and to $11.50/bbl for those under development during 1997.

A separate type of argument favoring reintroduction of royalties on new fields was put forward by some academics, on the grounds that the state, which had title to the reserves, should consequentially receive a royalty on all production. Such impositions would remain, even if the consequence were that fields would be rendered uneconomic under current oil price conditions. It was argued that, at some future date, higher prices would ensure that fields could be exploited profitably.

This argument has little merit and is unlikely to have had much influence on governmental thinking. The overriding objective in petroleum policy is (or should be) to maximize total returns from exploitation in present value terms. Introducing royalties that result in slower rates of development and depletion than the free market produces may not be consistent with this objective. Oil prices may stay low for some years ahead, and, even if the pace of development is fostered in subsequent years by higher prices, the net effect could well be that total returns are reduced in present value terms.

Field Economics

Evidence from the government’s September statement is that officials were primarily influenced, in their decision not to make any tax changes, by the effect of collapsed oil prices in reducing taxable capacity. Possible adverse repercussions on exploration and development activity were clearly of major concern.

Empirical evidence confirms that these fears were justified. At the new field decision point, the author conducted an assessment of prospective returns on 40 fields that are being assessed for development by licensees, but where development approval has not yet been obtained. Basic field data were validated by the operators involved. Table 1 shows the number of fields from this group of 40 that have positive returns in the form of positive net present values (NPVs), at 10% and 15% real discount rates under three real oil and gas price scenarios ($/barrel and pence/therm).

Under an $18/15-pence ($18 per bbl/15 pence per therm) price scenario, 38 of the 40 fields are acceptable under all conditions examined. In a $15/13-pence case, 31 have positive post-tax returns under the highest threshold rate and post-tax conditions. However, the Brent price has averaged $11 to $13/bbl this year, and under the $12/10-pence scenario, there is a dramatic fall in the number of viable projects. Only 20 are acceptable after tax.

Taxable capacity of the whole sector thus falls substantially under current price conditions. With corporation tax at 30%, the share of economic rents collected with a 10% cost of capital is around 30% to 40% on the more attractive fields, but much higher on a significant number of more marginal projects. This reflects the interaction of the 10% discount rate and the 25% declining balance relief for field investment.

At the exploration decision point, the prospective returns facing an explorationist were estimated, based on recent success rates and size of discoveries. Returns are measured by expected monetary values (EMVs) at a 10% cost of capital. In the Southern Gas basin, where the chance of discovery is higher, a 15-pence/therm price yields an expected return of about 10%. This falls to 7.5% under the 13-pence case. On the optimistic assumption that success rates would significantly exceed recent experience, the expected rate of return was increased by only around one percentage point.

British officials were influenced not to make any tax changes by the effect of collapsed oil prices in reducing taxable capacity. Possible adverse repercussions on E&P were clearly of major concern.

In the rest of the UKCS, which is dominated by oil, the expected return facing an explorationist, based on historic success rates, was found to be 8% under an $18/bbl price scenario and 5% under the $15 case. When exploratory success rates significantly greater than historic ones were employed, the expected return was found to be 12% under an $18 price case and 8% in a $15 case.

The evidence suggests that there is no excess taxable capacity at the exploration stage. Expected returns hardly cover the cost of capital at current oil and gas prices. Explorationists tend to be optimistic, with above-average success rates anticipated. Of course, if a substantial discovery is made, the return on such a project could be attractive.

Natural Gas Market

During 1998, the North Sea gas industry also has been affected by the government’s "Review of Energy Sources for Power Generation." This was precipitated by the prospective problems facing the UK coal industry, due to the increasing use of natural gas for power generation. The Blair regime has proposed imposing a moratorium on new gas-fired power stations, until the time at which officials are satisfied that a level playing field has been established in the wholesale electricity market.

At the time this article was written, the government’s final decision in the form of a "white paper" was awaited, but it is very likely that the initial proposals will be implemented. This will have repercussions for the UK gas market. Already, this is personified by production capacity in excess of demand, with low producer prices as a result.

The power generation segment of the gas market is, by far, the fastest growing in the UK. Imposing a moratorium would reduce the rate of growth in gas demand and increase market uncertainty for a period that is, as yet, unclear. Other things being equal, the gas price will be lower than it otherwise would be, and exploration and development incentives will be reduced.

Introduction of the moratorium proposal comes at a time when a very large new field, Britannia, goes onstream. Further, development of other gas fields, such as Elgin, Franklin, Shearwater and the ETAP group, proceeds. Together, these fields ensure a substantial increase in gas supply capacity. This would reinforce the "gas bubble," but some relief will be given by the opening of the Interconnector pipeline between Bacton and Zeebrugge. The line has a 20-Bcm/year (706-Bcf/year) capacity. Currently, UK producers have obtained export contracts that total around 10 Bcm/year (353 Bcf/year).

The UK gas industry’s short-term future depends, to a significant extent, on the ability of British producers to obtain additional export contracts. While some progress has been made to liberalize the gas market on the European continent with the passing of the EU Gas Directive, there are still many restrictions on the ability of UK exporters to transport and market gas. Further, with downward pressure on prices existing on the continent, it is not clear whether significant new export contracts can be made profitably.

An additional complication is the effect of the signing of the new treaty between the UK and Norway. This will result in more imports of gas into the UK. For example, Statoil’s British subsidiary recently agreed to buy 550 MMcm/year (19.4 Bcf/year) through the Frigg pipeline, beginning in 2001. The net effect is that competition in the UK gas market will continue to be strong.

Thus, operating conditions on the UKCS have been very tough this year. The uncertainty of the fiscal review has been removed for the time being, but other market and regulatory problems persist.

Bibliography

Kemp, A. G., and L. Stephen, "Exploration and development prospects in the UKCS: the 1998 perspective," North Sea Study Occasional Paper No. 68, pp. 21, Department of Economics, University of Aberdeen, September 1998.

The author

Alexander G. Kemp is professor of economics at the University of Aberdeen. He was formerly lecturer, senior lecturer and reader. He also worked previously for Shell, the University of Strathclyde and the University of Nairobi. For many years, Professor Kemp has specialized in petroleum economics research, with special reference to licensing and taxation issues. He has published more than 100 books and papers in this field, including Petroleum Rent Collection Around the World, Institute for Research on Public Policy (Canada), 1988. He is European editor of the Energy Journal, and editorial advisor to World Oil and other academic/professional journals. Professor Kemp is director of Aberdeen University Petroleum and Economic Consultants (AUPEC), which provides consultancy services in petroleum economics.

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