Against the backdrop of high oil and gas prices, the potential for further price increases in future, Britain's growing dependence on gas imports, and increasing concerns over the security of future oil and gas supplies, the scope for recovering more oil and gas from the UK Continental Shelf remains a key aspect of UK energy policy.
Although still subject to a wide range of uncertainty, it is broadly estimated that of the order of a third of our ultimately recoverable reserves of oil and gas have yet to be produced. There is no disagreement that a prime objective of UK energy policy is to maximise the quantities that ultimately can be recovered economically. But in practice what are the issues and questions that need to be addressed if this objective is to be served?
This BEA Workshop examined these issues from various perspectives: technical and operational factors, including the integrity of ageing assets and infrastructure, and abandonment policy, standards and costs; fiscal policy; the implications of higher oil and gas prices; the incentivisation of further exploration, appraisal and development; and new patterns of ownership and related aspects of financing.
Our three presentations complemented each other very well: from Mike Tholen's coverage of the big industry picture; to Brian English's portrayal of the extremely successful, though high risk, development of BG Group's Buzzard Field - a prime example of a big, well-established operator able to use all the potential of today's technology and capabilities; to a fascinating analysis by Mark McAllister, Chief Executive and founder of the UK independent operator, Fairfield Energy, one of the new enterprises adapted to realise the opportunities of a mature basin. A brief thumb-sketch of their remarks follows:
| Mike Tholen, the Economics and Commercial Director for UKOOA, seeks to foster a business environment that sustains the competitiveness of this mature oil and gas province. Particular responsibilities within the oil and gas industry trade body include fiscal and energy policy and regulatory affairs. He is actively engaged with HM Treasury and DTI on the future of the UK oil and gas fiscal and regulatory regime, which will be critical to deliver the full potential of the basin. In recent years he has worked closely with Ofgem and DTI on the evolution the gas market and the contribution the UK's own gas supplies can make to UK security of supply. Prior to joining UKOOA he worked with Shell for 20 years, latterly holding a variety of commercial positions including economics and planning manager for their upstream UK gas business and Offshore Infrastructure Manager in the Netherlands. |
Mike Tholen led off with an overview of the 2006 UKOOA Activity Survey providing a forecast of potential exploration and appraisal activity over the next three years and a picture of the investment and new developments likely to occur over the life of the basin. Quite evidently, European economies will remain primarily carbon-based with demand expected to rise to 80% by 2020. Even if Renewables grew solidly over the next few years, they would still form only part of the energy mix of the future. The UK is expected to be self sufficient in oil in 2007/8 but is now more likely to be a net oil importer by 2010. Indigenous gas could still meet more than 60% of UK demand in 2010.
Clearly the UKCS will continue to make a crucial contribution to UK security of supply and 2006 had generally been quite a good year for oil and gas productivity. UKCS remains a substantial employer, creating strong economic activity, and though tax revenues are down a little, is still a big contributor to the UK economy. But the UKOOA survey indicates that the future will be much more challenging. Three key factors dominate: a more rapid than expected decline in production; significant cost inflation in 2006; and the forecast of a reduction in investment in 2007, after a sharp rise in 2006. It seems evident that the UK Offshore oil and gas province is becoming less competitive and less able to attract investment, which has negative implications for future production levels and forecast fiscal revenues.
Nonetheless, even after 40 years, the UKCS continues to be an active oil and gas basin. Capital investment in 2006 at £5.6 billion was the highest since 1998 and investors strive to deliver sustainable businesses in this mature province. Investment levels are strongly influenced by the rise and fall of oil prices, and it is expected that 2007/08 will show a big step back in investment. Though start-ups have been slower than planned - 20 hoped but only 10 actual - current plans expect to recover 10.3 billion boe (barrels of oil and gas equivalent) from existing fields and currently identified developments. The supply chain is rising to the challenge, servicing oil and gas demand both in the UK and abroad; securing access to rigs, resources and manpower is critical to sustain the current pace of development. The market is settling down after a period of intense activity, which should help to foster more long-term commercial relationships within the basin. Providing UKCS operators can attract the resources and funds to develop them, some 52 projects are planned over the next three years to 2009. However, drilling rig resources are scarce and falling, so canny asset management will be a key factor to achieving the levels of production forecast.
Exploration and Appraisal (E&A) activity has increased over the past 2 years and remains strong. This must be sustained and must lead to the swift conversion of discoveries (36% success rate in 2006) into developments, but much depends on the commercial attractiveness. 50 projects are currently ongoing which it is hoped will put up production levels, though these are expected to gradually decline by 2010.
The emphasis in 2006 was on appraisal drilling, primarily targeted at well-explored areas like the Central North Sea and Southern Gas Basin, a trend that is expected to continue into 2007/8. Following successful exploration in 2005, there was little new exploration activity in the Atlantic Margin region where potential rewards and risks are higher, prompting concern that the high level of E&A activity is not optimizing the yet-to-find potential. However exploration is expected to dominate E&A drilling over the next 2 years, possibly as a result of Frontier License commitment deadlines and more drilling on fallow acreage. The volume discovered per exploration well was 15 million boe, benefiting from one large discovery in 2006, though recent years have more typically been around 10 million boe. However, 96% of future exploration prospects are expected to be less than 50 million boe and 88% less than 20 million boe in size on a risked basis.
More worrying are the challenges to UKCS business as, despite prolonged high investment, the production trend (down 9% in 2006) continues to decrease over the next decade. Delays in the start up of new projects, increased maintenance and reservoir performance have all contributed to the drop in production, although some of the production lost over the next few years may ultimately be recovered provided sufficient new projects come on stream. High costs combined with typically small opportunities and increased taxation makes it harder to attract investment into the UKCS. Tax uncertainties are making companies much more cautious and some are pulling out of the UKCS altogether. An expected sharp fall in investment to around £4-4.5 billion in 2007 will have a tangible impact on production and revenues both to Industry and Government as total expenditure on operating and technical costs from 2007/10 rises 25% higher than forecast a year ago. Cost pressures and declining production from existing fields risk shortening the life of existing infrastructure.
Uncertainty regarding the fiscal and regulatory treatment of decommissioning, combined with high oil prices, has impacted on asset trading, with no new entrants in 2005/06. Sustained asset trading is essential for the health of the basin, as it attracts new investment and is seen to enhance economic recovery. He noted that oil demand has not risen much in the UK for some time, whilst gas demand has been much stronger. There is still great potential for UKCS production but the challenge rests in producing the "Better Future" forecast, encouraging competitiveness and acquiring and developing new skills.
Conclusions:
•There are clear signs that the UK offshore oil and gas province is becoming less competitive and less able to attract investment. That must be addressed now if we are to recover the maximum amount of oil and gas - potentially some 16 to 25 billion boe.
• However, without continuing and sustained interest, 45% of pipelines and infrastructure could close by 2020 rendering further recovery of oil and gas uneconomic in areas of the UKCS.
• Government and Industry must engage in an active and productive dialogue to prolong security of supply and maximize the recovery of oil and gas.
• The pace of exploration in the North Sea must be kept up.
• The future of the UKCS will rely on the ability to sustain exploration and continue to attract investment in new discoveries and existing fields. Extraction from Brownfields (i.e. what can be squeezed out of existing production wells) holds great potential, and together with E&A and new development, could extend the life of the UKCS basin by 20-30 years.
• Given the decline in the UK's competitive position, oil and gas companies, the supply chain and Government need to focus on the challenges faced in operating in a mature basin and to properly consider how each can contribute to overcoming them, focusing on innovation, cost-management and balancing the risk-reward relationship between Government and companies.
| "The Buzzard Story - technical & operational factors affecting ultimate recovery " | Brian English has worked for 29 years within the upstream oil and gas industry in a variety of technical, operations and project management positions, within the U.K. and abroad. His international assignments have included periods spent in Canada, Kazakhstan and Egypt. Brian joined the BG Group in 1992 following 14 years with BP and is currently working as the Buzzard Project Co-ordinator, responsible for representing BG's interests in this major North Sea oilfield development.He holds a M.A. from Cambridge University in Natural Sciences and a M.Eng. from Heriot-Watt University Edinburgh in Petroleum Engineering, and is a Chartered Engineer with the Institute of Materials, Minerals & Mining. |
| "New patterns of Ownership & Financing: new-entrant Independent Operations " | Mark McAllister is currently Chief Executive of Fairfield Energy, an oil company focussed on the North Sea and based in Staines. Details of Fairfield can be found at www.fairfield-energy.com. As a founder of Acorn Oil & Gas, Mark served as Acorn's Managing Director from its inception in 2001 until the foundation of Fairfield in November 2005. He had previously been a member of the senior management team at LASMO and was Managing Director, Europe and North Africa at the time of the acquisition of LASMO by Eni in 2001. Previously, Mark had been on the Executive team at Monument Exploration, where he was Director of Operations. Mark is a Petroleum Engineer by discipline and began his North Sea career in 1979 at Conoco. He has worked for a number of companies both large and small, mainly in the North Sea but also in the Former Soviet Union and North Africa. He has an MA in Engineering from Cambridge University (1979) and a BA in Theology from the London Bible College (1991). |
Mark McAllister's company, Fairfield Energy, as independent operator created in November 2005, is one of the new breed of companies set to exploit the remaining oil and gas reserves of the North Sea. Mark briefly described the operating strategy, management structure of Fairfield Energy, which is supported by equity from a syndicate of North American and European private investors, led by Warburg Pincus. Fairfield Energy's strategy is to create value through the appraisal and development of known hydrocarbons with associated low risk exploration. Key to delivering this strategy successfully, as for any oil production project, is to possess outstanding subsurface technical skills combined with commercial creativity and disciplined investment.
Fairfield is currently focussing on two areas, Maureen and Crawford, and he illustrated the location and topography of each of these fields. The Palaeocene reservoir of the abandoned field, Maureen, probably retains around 50% of its original 400mmb oil in place, and is a possible CO2 injection candidate. Crawford Field, with a likely STOIIP of 140mmb yet to be extracted, shows significant appraisal/exploration potential using modern 3D seismic mapping techniques, and with the application of multi-laterals or horizontal fracs. Mark outlined four possible business models that any new company wishing to make money in the North Sea could concentrate upon, and described some of the incentives and challenges each approach could face.
Exploration: Prospects are improving. Many 4th-round licences have been held for very long periods, and under the historic licence system, are ripe for takeover by new operators. The fallow blocks process is encouraging an increased rate of turnover, and as the vast majority of Promote companies do not have the money to drill, Promote Licences are generating much activity with operators that do have such resources. There is better access to equity for start-ups, though for public companies, the scale of new exploration is often too small to offer significant returns, whilst private investors are traditionally wary of exploration risks. Also, the lack of tax incentives for exploration can lead to poor decision-making, and the pace of drilling is critical. To achieve UKOOA forecasts of recoverable reserves will require some 50-100 wells per year, posing a huge challenge in the context of the cost/revenue gap - e.g. the oil price has increased three-fold, but rig rates have increased ten-fold.
Undeveloped Discoveries: The fallow discovery process must be accelerated. Moribund discoveries, which are all undeveloped for very good reasons (e.g. heavy oil, tight reservoir, etc.) must be marketed more aggressively. Access to infrastructure needs to be easier, and the scope for abuse by infrastructure owners must be curbed. New entrant operators generally do not have the benefit of the balanced portfolios of resources and assets enjoyed by large, well-established UKCS operators. They therefore need access to debt finance, and already banks are becoming more flexible on financing small developments. However, risk spread is still an issue for lenders, and there is increased competition for assets, particularly as much of the value is now given up in the purchase price.
Abandoned Fields: Mark listed some of the multiple reasons for abandonment, pointing out that with the application of new technology, the potential for revisiting abandoned fields needs a different way of thinking. Already, the DTI and Treasury have shown their commitment to development activity by removing Petroleum Revenue Tax (PRT), but more flexibility is required to encourage new developments while old facilities are decommissioned. Section 29, which ensures that Abandonment costs remain the responsibility of the former owners, affects transfers to new entrant companies. Letter-of-Credit (LOC) arrangements between sellers and new owners are commonly required as part of sell-on deals to guarantee that the new owner will cover Section 29 costs, but smaller resourced, new entrant companies cannot compete with the big companies that have balanced funding portfolios. Clearly, the challenges of infrastructure, debt finance and competition are similar to those for undeveloped discoveries.
Mature Production "Brownfields": While he agreed with both Mike and Brian that extraction from 'brownfield developments' could offer the most attractive investment/return ratios for North Sea new entrant businesses, there were still a number of disincentives. Short-term oil prices, which are now in flux, will cause significant investment hedging for 3-5 years in order to match seller expectations. Though the UKOOA standard DSA is a good step forward in rationalising decommissioning security requirements, sellers are still wary of Section 29 issues, and banks and investors find it strange to tie up funds in LOCs. There are unresolved questions about the future tax regime, and assumptions about PRT rebates on abandonment make huge differences to the value of a project. Finally, there can be human resource constraints, as many small operators rely heavily on contractors as the Duty Holder, and all companies are struggling to replace an ageing work force.
Conclusions:
• The UKCS remains an attractive place for new investors. The majors are driven to invest elsewhere by reserves replacement, but UKCS reserve opportunities are greater than those of the shallow Gulf of Mexico.
• The cost base is a major challenge. Globally, price increases have outstripped the oil price.
• The UKCS has high costs due to the physical environment, the regulatory environment - exacerbated by the EU - and a high cost culture that shows little sign of changing.
• Fiscal regime stability is vital. E&P investments take 10-20 years to mature and governments must stop tinkering with the tax system. The playing field must be levelled if new entrant UKCS operators are to be encouraged to develop and maximise utilisation of the remaining life of the Basin.