Memorandum submitted by BP
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 three 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 £1.5 billion 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:
— The safe and efficient operation
of existing producing fields to achieve the highest possible recovery
of oil and gas from individual reservoirs.
— Continuing significant capital investment
at sufficient levels to extend the life of existing onshore and
offshore infrastructure and to find and develop new prospects.
— 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 of 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:
— A material reduction in the rate
of SCT (back to the level when oil was last at $40).
— A capital uplift to facilitate new
investment in existing fields.
— 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% 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% 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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