Memorandum submitted by BP (UKOG 1)
Introduction
1. Since the origins of oil and gas activities in the United Kingdom Continental Shelf (UKCS), BP has remained one of the largest and most committed investors in the Province - a position we wish to continue. At the end of 2008, we had an estimated resource base of some 3 billion barrels of oil equivalent (boe) still to be recovered from the North Sea as a whole, most of which is in the UKCS. We operate 31 producing fields in the UKCS and have two major decommissioning projects currently underway. BP's total expenditure in the UKCS (capital and operating expenditure) was some £1.5bn in 2008, and we expect to maintain investment at this level over the next few years.
2. While there is significant remaining potential within the UKCS - Oil and Gas UK estimates that there are up to 25 billion boe to be recovered, although only around 10 billion boe of this total has been identified in defined projects - there are massive challenges to be overcome if this potential is to be realised. Fundamentally, these challenges derive from the inescapable fact that the UKCS is now a very mature basin where the relentless pressure from declining field sizes, falling production and rising costs is undermining the economics of the remaining opportunities. It is only prudent to assume that maintaining production from existing fields offers the best chance of extending the life of the UKCS, given their critical role in extending the life in the infrastructure legacy.
3. Even with the oil price at high levels, the UKCS must continuously battle to reduce costs in order to remain competitive with other global opportunities. At today's oil price, this battle translates itself into a struggle for survival. With this as background, our comments on the issues raised by the Committee of special relevance to BP's expertise and experience are as follows.
How can the UK's remaining offshore oil and gas reserves be exploited most effectively? What barriers are there to exploiting such reserves?
How effective is the current fiscal and regulatory regime in which the industry operates?
4. We address these two questions together, because in many ways the fiscal and regulatory regime constitutes one of the biggest "barriers" to exploiting UKCS reserves. This is not to imply that, in recent years, the UKCS Fiscal Regime has been draconian or uncompetitive in global terms. The difficulty is that it has not adapted sufficiently to the needs of a mature basin. One of the characteristics of a mature basin is that geologically and commercially, every aspect of the operation becomes much more difficult. Many of these aspects are beyond human influence; but this means that those which are capable of adjustment (i.e. regulatory and fiscal) become even more significant.
5. The key factors for maximising the potential of these remaining reserves are: o The safe and efficient operation of existing producing fields to achieve the highest possible recovery of oil and gas from individual reservoirs; o Continuing significant capital investment at sufficient levels to extend the life of existing onshore and offshore infrastructure and to find and develop new prospects; o A competitive and less complex fiscal regime which recognises the
growing challenges facing the North Sea industry and the need to reduce the tax
burden on a sustainable basis as the basin continues to mature. 6. The major barrier to exploiting the remaining reserves is the risk that declining production - combined with rising costs, low oil and gas prices and the legacy of a high tax burden - all together constitute a business environment which increasingly threatens the North Sea's competitiveness. This would put at risk the investment required to sustain activity levels in exploration and appraisal, new field development and extracting more oil and gas from existing fields.
7. We now face this situation in the UKCS,
as evidenced by the recently published Oil and Gas UK 2008 Activity Survey
which forecasts a reduction in capital investment, exploration drilling and new
field development in 2009 and 2010. Only a third of new developments currently
under consideration "break even" with the current cost base and tax regime,
should oil prices stay in the $40 to $50 per barrel range. 8. The area west of Shetland demonstrates the point dramatically. Here, BP operates the first, and currently only, fields in production - the deepwater Foinaven and Schiehallion fields and the Clair field. We are currently appraising the potential for further development of the Clair field and continued development of Foinaven and Schiehallion through infill drilling programmes and the identification of satellite development opportunities.
9. Many of the other discoveries which have been made West of Shetland are marginal and BP believes that a reduction in the fiscal burden is required if more of the potential west of Shetland is to be unlocked both from new discoveries, existing undeveloped discoveries and fields in production. The Government's proposed Value Allowance mechanism only partially addresses the basin challenges as its scope is limited exclusively to certain narrowly defined categories new fields. It is important that investment incentives are also made available to encourage investment in existing fields and should be applied as widely as possible, including west of Shetland.
10. Overall, the
current fiscal regime provides a legacy of complexity and imposes a tax burden which
is inappropriate to the increasing maturity of the basin. When oil prices were
last at current levels (in 2004), production levels were higher, and both costs
and taxes were lower. The Government's
recent proposals, including a Value Allowance to be set against SCT, are
welcome but on their own will prove to be a wholly inadequate response, given
that they were developed at a time when the oil price exceeded $100 a barrel. The
proposal risks fragmenting the fiscal regime by the introduction of a wide
range of fiscal burdens according to the nature of the potential development opportunity.
Value Allowance by itself cannot make the material difference required in the current economic and oil price environment. It
will also further complicate the already excessively complex fiscal regime,
counter to BP and industry advocacy of simplification and the desired move
towards a level playing field for investment decisions. A more appropriate
fiscal reform would be a straight forward and significant reduction of the rate
of SCT, which would achieve more effectively and simply the objectives held out
in the Value Allowance proposal. 11. If, however, current financial constraints rule out this option (remembering that there are ways its costs could be contained and postponed) - and if Value Allowance is all that can be offered - then the Allowance should be made large enough to make a difference, and should be applied as broadly as possible with a focus on existing fields which are uncompetitive in a $40 oil world. More importantly, incentives must be made available to encourage incremental investment options in existing fields through the provision of capital uplift.
12. Thus, our fiscal preferences are: o A material reduction in the rate of SCT (back to the level when oil was last at $40). o A capital uplift to facilitate new investment in existing fields. o For new fields, a value allowance with qualifying criteria as broad as possible (including all new fields west of Shetland)
What can be done to minimize the environmental impact of exploiting the reserves? How should this be encouraged and/or financed?
13. It is a constant priority and principle of our continuing operations within the UKCS to minimize the detrimental environmental impact of our activities. This is part of our overall obligations which we have shouldered voluntarily, irrespective of what is or is not dictated by external legislation and regulation.
14. That said, policy makers need to be mindful of the extent to which the operation of the EU Emissions Trading System in Phase III is likely to have an increasingly negative impact on ultimate recovery levels throughout the UKCS. This would be the direct consequence of the higher field level operating costs associated with a progressive move towards increased auctioning of allowances. It should be noted, in this context, that these costs cannot be passed on to consumers due to the global nature of the oil market. Oil and Gas UK has recently estimated that if there were to be a requirement for the UK oil and gas industry to buy all of its allowances at auction under ETS Phase III (the ultimate EU ambition), it could result in the loss of up to one billion barrels of UK oil and gas production.
15. For some installations, the reality of 100 per cent auctioning is imminent. As a consequence of the requirement that all emissions associated with electricity generation are to be denied any free allowances in phase III of the EU ETS, it is estimated that a number of BP's installations will be obliged to purchase in excess of 90 per cent of their required allowances from the very start of Phase III in 2013.
16. The unfortunate reality is that this significant loss to the UK economy (and in terms of Security of Supply) would provide no global environmental benefit as the shut in production would merely be replaced by other production from elsewhere in the world, quite possibly with a greater CO2 footprint.
Conclusions
17. We have concentrated on those questions raised by the Committee which we feel are of special importance to BP and where we have something distinctive to contribute. This is not to minimize the importance of the other areas; but in terms of current realities, we concentrate on those areas which have maximum importance and where we believe the Government has the greatest discretion to bring about improvements.
March 2009
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