Economic Report 2002 Index

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Events in 2002 UK Budget On 17th April, the Chancellor announced the first fundamental change to the fiscal regime for the North Sea for almost ten years. The timing of the changes, that significantly increased the tax burden on the industry, surprised the industry as they have been made at a time when the UKCS faces perhaps its greatest challenge as competitiveness deteriorates. The tax changes were: The introduction of a new tax, Supplementary Corporation Tax (SCT), at a rate of 10%, which increases the Corporation Tax (CT) rate to 40%. (Interest expenses are not allowed as a deduction against the new tax) Introduction of a 100% First Year Allowance (FYA) on investment. The Abolition of Royalty from 1st January 2003 The Budget's impact on UKCS competitiveness and investor's confidence is discussed in the previous section. The lack of transitional arrangements for those most seriously affected by such a significant adverse fiscal change is unprecedented. Whilst Royalty abolition and the introduction of the 100% FYA are welcome alleviating measures they do not compensate for the impact of the 10% SCT. The introduction of the 100% FYA does not reduce the amount of CT paid; it simply determines when it is paid. All new projects in the UKCS will pay 33% more CT than was previously the case.   BOX 9 Budget Measures - Summary Impacts Reduces industry cash flow by £8 billion in period to 2010 Large earnings reduction in 2002 - some £2 billion across industry Measures take no account of oil prices returning to sustainable levels Nearly £4 billion in extra tax at $15/bbl and £1 billion at $10/bbl Retrospective change undermines industry confidence Denial of interest relief will deter new entrants/start-up companies and increase funding costs PILOT vision for production and investment now more difficult to achieve.   Box 9 summarises the impact of the Budget measures. Reported earnings reductions of £2 billion in 2002 give a clear message as to the severity of the tax reform and is one that inevitably has had a high profile with the senior management of oil and gas companies. The aggregate impact of the Budget measures is shown in Figure 17. They will remove an extra £8 billion in tax from the industry up to 2010 based on the Government's Budget oil price assumption of $21.5/bbl. The measures also raise significant tax at low oil prices. The tax changes have upset the delicate economic equilibrium whereby the UKCS's high cost structure and poor prospectivity was alleviated by a fiscal policy which assisted in delivering basin competitiveness to some degree. If the UKCS is to continue to attract significant investment capital in the face of more attractive (higher reserve potential and lower costs) global oil and gas provinces, all stakeholders in the industry are going to have to actively seek ways to improve the basin's competitiveness and capital efficiency. Financing costs: The industry remains concerned that the new SCT denies deductions for interest expense, unlike mainstream Corporation Tax. The capital intensive nature of the industry means that access to debt markets is critical for new entrants and start-up companies who are traditionally more highly geared than the large established players. The failure to allow deductions for financing costs seems likely to damage the prospects of new entrants and start-ups. The denial of interest costs is of particular concern to US companies as it raises the question whether SCT will be recognised as a creditable tax for US tax compliance purposes. If SCT is held not to be so creditable, this would further reduce the attractions of the UK as a place in which to invest. Future Activity: The industry failed to persuade the Government to modify the tax proposals. The legacy is a fiscal regime which, in many ways, is inappropriate to the challenges ahead. One area of industry focus will be to maximise opportunities in existing fields. These fields now face tax rates ranging from 40% to 70%, and a 70% rate cannot be appropriate in an environment where opportunities and returns are more marginal. Furthermore, infrastructure is taxed at rates which vary from 30% to 70%. At the higher end this is likely to discourage the desired reduction in tariffs necessary to ensure maximum exploitation of existing and new discoveries. Exploration: 16 exploration wells were drilled in 2002, the lowest (in common with 1999) since North Sea exploration commenced in 1965. However, some significant discoveries have been announced, such as Forvie North. Figure 18 illustrates that the industry is increasingly focused on development and infill wells. Simply measuring the number of wells drilled may give a misleading picture. Increasingly improved seismic imaging better delineates exploration prospect potential and can prevent dry holes being drilled. This is manifested in a global trend towards higher exploration success rates; UKCS success rates show similar if less pronounced trends. Initiatives to stimulate more exploration activity and risk taking are under consideration by Government and industry. The explanation for the low activity in the UKCS primarily relates to the maturity of the UK as an oil and gas province and the more attractive opportunities available elsewhere in the world. The average discovery size in the UKCS over recent years has been some 25-30 million boe, although the 2001 Buzzard discovery, reportedly some 500 million boe, was the largest discovery on the UKCS for over 10 years. When unsuccessful dry exploration wells are included, the trend over recent years has been an average of 10 million boe discovered per well drilled; the expected outcome for 2002 is in line with this trend. The results of the Twentieth UK Offshore Licensing Round were announced in July 2002. Of he 270 blocks/part blocks originally offered 36 blocks/part blocks were awarded to 33 companies. Four new entrants were attracted to the UKCS. New Development Approvals Following a spate of new development authorisations in 2001, when spending of £2,500 million on 21 oil and gas projects (including incremental developments within existing fields), was announced, and in early 2002, when a further £730 million spending on 8 more projects received development approval, the scale of new developments has dropped dramatically. Since May 2002, a further eleven projects have been approved with estimated expenditure of £560 million, and reserves of 172 million boe. Compared with the projects authorised in 2001, which yield additional reserves totaling some 900 million boe, the projects in 2002 will yield only half this amount. The near future should see a temporary reversal of this trend when development plans for Buzzard are finalised. Box 10 identifies projects announced in 2002.   BOX 10 Project name (Announced in 2002) Dev. Type Operator Cost (£ million) Reserves (million boe) 2002 Approval Madoes Oil BP 100 34 Jan Mirren Oil BP 70 23 Jan Maclure Oil BP 50 20 Jan Bains Gas Centrica 25 8 Feb Brent alpha redevelopment Oil incr. Shell 45 16 Feb Goldeneye Condensate Shell 265 165 March Tullich Oil Kerr McGee 110 22 March Viscount Gas ConocoPhillips 65 30 April Sycamore Oil Venture 90 20 May Rivers (5 fields) Gas Burlington 165 42 June Helvellyn Gas ATP 25 8 July Braemar Condensate Marathon 40 30 Aug Foinaven T25 Oil incr. BP 20 7 Aug Brae B to Miller pipeline Gas incr. Marathon 45 - Aug Jade Addendum Gas incr. ConocoPhillips 10 5 Oct Boyle Gas BP 10 9 Oct Ardmore Oil Tuscan 70 25 Oct Douglas West Oil BHP Billiton 15 6 Nov Clapham Oil PetroCanada 70 20 Dec   Total £1,290 470   UK-Norway Co-operation The UK and Norway share a common aspiration to develop optimally the North Sea's oil and gas reserves. Following an initiative from the respective UK and Norwegian Energy Ministers a joint government-industry work group was commissioned at the start of 2002 to study options for the most favourable development of resources close to the UK-Norway median line. The expectation was that... ...improved co-operation could generate additional value for all stakeholders. The work group concluded that there was a potential pre-tax prize of up to $2 billion that could be unlocked through closer co-operation between the two sectors. Figure 21 illustrates existing and possible gas pipelines that may play their part in this co-operative proposal. In all some 14 recommendations were made covering inter alia safety, the need for a new UK-Norway Treaty, a review of the UKCS fiscal regime for infrastructure and creating better opportunities for the supply chain. For convenience, a co-operation zone, extending 60 km on each side of the median line, was delineated in order to assess the potential for better co-operation (see Figure 22). It was found that the assets and infrastructure within this zone are very considerable and represent: Nearly 12 billion barrels oil equivalent remaining in the period to 2010 and a further 5 billion in the following decade. Reserves split approximately 50:50 between UK and Norway Current production of 4.5 million boepd Some $71 billion of remaining expenditure in the period to 2010, comprising capex of $27billion, opex of $41 billion and removal costs $3 billion (all in constant 2002 prices). Expenditure of a further $35 billion is predicted during the following ten years to 2020. Given the scale of the remaining resource potential, and an expected expenditure of circa $71 billion by 2010, even modest success from improved co?operation should yield considerable improvements in value. Box 11 outlines some areas where co?operation may produce benefits. An industry initiative, to examine the feasibility of reducing the tax rate on tariff income (i.e. the fee paid by third parties to infrastructure owners to process or transport their products) so that the tariff itself may be reduced which would encourage marginal new developments and exploration, is being evaluated. This is an example of the kind of co-operation that will be required from stakeholders to achieve optimum economic recovery of the nation's oil and gas reserves.   Box 11: UK-Norway Co-operation Work Group Developments and re-developments Access to new cross-border transport and/or processing solutions will increase available development options. Closer co?operation should make cross-border utilization of existing infrastructure (particularly pipelines) more efficient. This will assist in minimising total costs of development and/or redevelopment. Reduced extraction costs (capex, opex, tariffs) of new developments should increase the expected value of exploration and thus give incentives to increase exploration activity near the median line. Closer co?operation offers the potential to accelerate development plans based on tiebacks across the median line. This will increase the value of currently 'stranded' discoveries and exploration prospects. Operational synergies Savings focused on reducing operating costs via logistics savings etc. Sharing of best practices. Decommissioning Greater economies of scale and synergies from decommissioning options covering a wider area   Asset Deals Over the six year period from 1996, the global oil industry has seen some significant changes in its structure. The drive for growth in shareholder returns, and greater cost efficiency has been a stimulus to transaction activity. Several of the 'majors' merged following the 1997-8 collapse in crude oil prices and the value of asset deals peaked in 1999. Subsequently, as the new 'supermajors' assessed their new portfolios and their strategic focus was sharpened, a period of rationalisation has occurred, providing opportunities for new entrants and 'niche players' to acquire assets. Recent deals such as BP's sale of Forties to Apache in January 2003 illustrates that this is a continuing process. At the same time, it is widely acknowledged that the UK Continental Shelf has reached a phase of maturity in which most, if not all, of the known giant field and infrastructure developments have probably occurred. Outwith the frontier areas to the West of the UK and the high cost high technology developments throughout the UKCS, future more conventional opportunities are, for the most part, likely to be found in exploring for and developing smaller fields. Differences in companies' strategic directions, requiring different skills and financial strengths, suggest that there is a significant potential for more transactions as niche opportunities are pursued, although continuing uncertainty over commodity prices may have prevented this potential from being unleashed to its full extent. Figure 23 illustrates the pattern of spending and the number of deals over the period. In 2002 there were only 31 deals (2001: 25) but the value of the transactions had increased to $5.1 billion (2001: $2.9 billion).