TAX REFORMS RAISE QUESTIONS FOR OIL INDUSTRY IN THE U.K.

Graham K. Kellas
Petroleum Economist Petroconsultants (U.K.) Ltd.
London

In a move to "eliminate tax rules which distort investment decisions," former U.K. Chancellor of the Exchequer Norman Lamont surprised the oil industry in his March budget speech.

The budget provoked an often bitter row, which has raged since then between the oil companies and government, and among the companies and government departments themselves.

Lamont announced a major reform to the petroleum revenue tax (PRT) applied to U.K. exploration and production. Here are the main features:

• PRT rate reduced to 50% from 75% effective July 1.

• PRT abolished for fields given development consent on or after Mar. 16, 1993.

• Abolition of PRT rules that allow expenditure on new exploration and appraisal to be set against profits of existing fields.

• Abolition of PRT tariff receipts allowance for tariff income from new nontaxable fields

• 10% PRT "cross field" development allowance abolished for nontaxable fields.

• Interest payments on losses carried back to be capped in line with the new PRT rate.

• Gas levy may be dropped for new contracts on previously PRT-exempt gas fields.

The changes, which will have a highly significant impact on the future of upstream petroleum activities in the U.K., have received a mixed response from the industry.

Although the system will be much simpler to apply in future, only companies with substantial PRT liabilities, in relation to their exploration commitments, will benefit significantly from the changes in the short to medium term. Companies with significant exploration programs and lower PRT liabilities are likely to be considerably worse off as a result of the changes unless they significantly reduce their planned exploration programs.

This article discusses how the changes might affect perceptions of the risk/reward balance inherent in future U.K. upstream activity.

EXISTING FIELDS

Many oil companies have been arguing for a reduction in the PRT rate in existing fields for some time. The argument has been that a marginal tax take in excess of 83% does not encourage savings in operating costs-which, in per barrel terms, are rising in most old fields-and discourages incremental investment in old fields.

By allowing companies a higher share of additional profits generated, the proposed reforms should reduce the apparent disincentives to cost cutting and future investment in existing fields.

The problem of the tax burden on fields in late life is, however, unlikely to be settled with introduction of a lower PRT rate. Two problems remain that will need to be addressed:

• Many old fields pay royalty which is, effectively, the same as an operating cost to the companies. In late field life, the impact of the royalty on operating margins will become increasingly significant and is likely to have to be reduced or removed to prevent premature abandonment of fields. A lower PRT rate may encourage operating cost reductions but is less likely to prevent early abandonment of fields than abolishing royalty, which would bring existing fields in line with those developed after 1982.

• It is believed that lowering the PRT rate will encourage more secondary and tertiary recovery schemes to be undertaken in existing fields. Studies of this problem have shown that while this may be true in some cases, similar results could be obtained by modifying the existing PRT rules so that incremental investments received uplift--135% of expenditures allowed as deductions--or an extension of the oil allowance for incremental production. Additionally, royalty could have been abolished or remitted for incremental production; again, it is likely this will have to be addressed in the future.

Decreasing the PRT rate is, therefore, only one way of encouraging enhanced profitability of existing fields. Lowering the PRT rate will, however, reduce government revenue from all PRT-paying fields, ensuring a lower tax take whether future investment is planned or not.

FUTURE FIELDS

Large fields given development consent after Mar. 16, 1993, will benefit significantly from abolition of PRT.

With removal of PRT from future fields, only corporation tax (CT) at 33% will be payable on field profits. This makes the U.K. tax take from new discoveries virtually the lowest in the world, providing potentially very high returns from future discoveries.

BP Exploration Co. Ltd. said this reform, along with the improvement to its own cash flow, provided a "significant impetus" to accelerated development plans of the Eastern Trough Area Project (ETAP), announced less than 2 months after the budget (OGJ, May 17, P. 18).

For most expected future field developments--significantly less than 100 million bbl of reserves--however, abolition of PRT will have little effect when considered on a project stand-alone basis.

The existing rules provided effective cover against PRT liability through a number of allowances, notably the "oil allowance," which provided for as much as 10 million metric tons (about 70 million bbl) of production to be exempt from PRT. The existing system, therefore, effectively provided the same after tax returns for most likely future developments.

Abolition of PRT removes the means by which the U.K. treasury could secure a significant proportion of any "windfall profits" from future oil price increases and/or low cost[high reserves developments.

Given that PRT was initially introduced for precisely this reason, it is likely that any government of the day would feel compelled to reintroduce PRT or something similar if oil prices return to high levels for a sustained period. This introduces more political/fiscal risk into oil company perceptions of potential returns from future discoveries and creates the possibility that a cruder, less flexible instrument might be introduced, such as the supplementary petroleum duty that applied in 1981-82.

E&A SPENDING

Since 1983, the "ring fence" around each field for PRT purposes has been extended to North Sea operations for exploration and appraisal (E&A) expenditure relief. The net cost of new E&A operations to a company with PRT and CT liabilities, therefore, has been less than 17% of the gross cost because immediate relief could be obtained by offsetting current PRT liabilities or reclaiming PRT paid in the past.

The sustained high level of exploration in the U.K. can, in large part, be attributed to this allowance. Many North Sea asset deals in the 1980s were driven by differences between companies' valuations of the "PRT shelter" for exploration costs an asset could provide. The removal of immediate relief for future exploration costs is the main cause of the controversy surrounding the proposals.

The U.K. Offshore Operators Association summed up the mood of many explorers by saying the changes would put a "substantial burden" on the industry by effectively quadrupling the cost of future exploration.

Thus, while potential returns from discoveries remain relatively very high, the proposed abolition of immediate PRT relief significantly reduces the amount of risk that can be associated with any prospect and, consequently, reduces the attractiveness of future exploration on an after-risk basis.

E&A costs in the U.K. remain among the highest in the world, and, combined with the decreasing expected discovery size, other countries' risk/reward balances will now compare more favorably with the U.K. despite lower expected returns from developed discoveries.

Many companies are, consequently, significantly reducing their U.K. E&A spending plans, which had initially been budgeted on the basis of immediate tax relief.

These companies include some, like Shell U.K. Ltd., which are supporters of the reform package. Indicative of the expected future decline in activity was the result of the 14th licensing round, announced in June 1993. Despite a similar number of blocks being awarded (110) to the 12th round, the number of well commitments was 45% lower.

TRANSITIONAL RELIEF

A main aim of many oil companies has been to persuade the government to provide transitional measures which will allow E&A expenditure to attain immediate tax relief for at least 3-4 years.

Companies with drilling commitments under the terms of licenses awarded under the 11th and 12th licensing rounds made those commitments on the basis that the existing system would prevail, or at least would get no worse. Without immediate PRT relief, many companies, particularly the independents, argued that they could not be held to their original commitments.

The intense lobbying by oil companies, service companies, and suppliers won a concession from the treasury in June, when it amended the proposals to allow each company up to 10 million ($15 million) for E&A expenditure incurred between 1993 budget day and Dec. 31, 1994.

Industry response to the concession has been lukewarm: Many companies that were most adversely affected by the initial proposals, such as Amerada Hess Ltd., will remain significantly worse off. The concession is likely however, to be sufficient to appease some of the smaller independents, such as Clyde Petroleum plc, Ledbury, U.K., and Hardy Oil & Gas plc, London.

Ukooa has stated that it believes the concession will "mitigate but not substantially alter the impact of the changes,

Throughout the months of debate on transitional relief the largest producers, and main beneficiaries of the reforms, have not been in favor of any changes to the initial proposals. This position results from a fear that any transitional provisions concerning E&A relief would be coupled with a more gradual reduction in the PRT rate.

Indeed, one member of Parliament did propose that the PRT rate be reduced gradually so that it reached 50% only in 1996. This was clearly detrimental to the large producers and has, therefore, resulted in a considerable divergence of support for transitional provisions within the industry.

SHIFTING THE BALANCE

The argument is whether high tax rates coupled with significant allowances, or low tax rates and negligible allowances, are more appropriate for a mature province that maintains a high success rate of discoveries, albeit of decreasing average size. There is common agreement that the abolition of PRT and E&A relief returns the North Sea to a high risk/high reward province, and this may be viewed, as it is by the government, as appropriate.

The absence of both a future means of capturing windfall profits and transitional relief for existing commitments, however, adds political and fiscal risk to perceptions of the U.K. that previously had given North Sea exploration an edge in the competitive international environment for exploration money.

In an international context, the U.K. has bucked the trend in these proposals bv providing higher profits from existing fields while making future exploration less attractive. The risk/reward balance has shifted considerably. Most future discoveries will provide no higher reward than under the existing regime while the associated risk for most companies has quadrupled.

It remains to be seen whether the perceived prospectivity of future exploration in the U.K. is high enough for companies to accept the higher risk or, as has been indicated by a large number of explorers, more interesting opportunities are now available elsewhere.

It appears very likely there will be a considerable downturn in exploration on the U.K. Continental Shelf.

The introduction of a limited amount of transitional relief may delay this trend, with a possible exploration surge as companies drill their obligation wells within the time allowed for tax relief. Thereafter the existing trend towards transferring exploration expenditure overseas is likely to be increased.

If this holds true, the future of the U.K. oil industry must be in jeopardy.

Copyright 1993 Oil & Gas Journal. All Rights Reserved.