North Sea: still attractive for some
Difficult times have led heavyweight operators to review their North Sea portfolios, but there is no shortage of buyers for their assets, Martin Quinlan writes
PRODUCTION from fields under the seas surrounding the UK still covers virtually all of the country's oil consumption and nearly three-quarters of its gas consumption – but operating them profitably has never been more challenging. Costs have escalated and the world's larger oil companies, which have pumped expertise and cash into the North Sea for decades, have been selling assets.
Most recently, Eni is seeking offers for a large package of North Sea interests, which includes holdings in more than 30 producing fields, while interests in another eight fields are on offer from Sumitomo. The sale of mature assets by the majors has been a trend for some time, becoming headline news when BP sold its Forties field to Apache in 2003. In recent years, Shell has been a big seller.
The buyers have tended to be small companies, often with few assets outside the North Sea. The government's Department of Energy and Climate Change (Decc) lists 51 companies as operators of producing oil and gas fields, of which fewer than half could be regarded as substantial international operators.
Cost-limitation, rather than making large discoveries, has become the key to success and the smaller companies say they can contain costs better than the majors. The majors, with their high staff numbers, top-of-the-range remuneration packages and high overheads – and, some say, inflated quotations from suppliers – need high-flowing fields to pay the bills. The flows from most of the UK's large early fields have now dwindled to about a 10th of their former peaks, so asset sales can benefit both parties.
The new owners are not just carrying out run-down operations. A new and fast-expanding entrant is Taqa Bratani, the UK subsidiary of Abu Dhabi National Energy, which says it is buying assets to build up "a cohesive business in the North Sea that is sustainable to 2020 and beyond". Remarkably – because the firm only made its first UK acquisition, covering non-operating interests, at the end of 2007 – Taqa Bratani has become a field operator and, in August, took over as operator of the Brent pipeline system.
This high-profile role, managing the 100,000 barrels a day (b/d) flow from about 20 fields to the Sullom Voe terminal, had been held by Shell since the Brent system started-up in the 1970s. Taqa Bratani has 16.0% of the Brent system (with Shell and ExxonMobil each holding around 27%, CNR holding nearly 13% and 10 other companies holding small shares) and it also holds 24.0% of the BP-operated Sullom Voe terminal.
In December, Taqa Bratani paid $0.631bn to acquire interests in seven oilfields from Shell and ExxonMobil, giving the firm the operatorship and 100%-ownership of the Tern, Kestrel, Eider, Cormorant North, Cormorant South and Pelican fields and a non-operating share in the Hudson field, together with the pipeline and terminal interests.
Taqa Bratani engaged Wood Group to act as duty-holder for the fields, but said it plans to take back that role before next summer, with Wood Group continuing as the operating and maintenance contractor. The firm expects to spend $0.5bn on the fields over the first three years to extend their lives. Production from the assets, about 40,000 barrels of oil-equivalent a day (boe/d), has already been lifted by the re-starting of water-injection. Taqa Bratani's first acquisition was of interests in Brae-area fields from Talisman and it has also made gas acquisitions recently in the Netherlands, giving the firm a total European production of 50,000 boe/d.
But successful acquirers and developers of assets can themselves be hunted-down. UK-based Venture Production, set up in 1997 to focus on stranded and under-exploited assets, spent the summer trying to fend-off a hostile bid from Centrica, but succumbed to an offer worth $2.01bn in August. Centrica is the owner of British Gas, the UK's largest gas retailer, and Venture's gas resources were a big attraction. The firm's production averaged 53,000 boe/d over the first six months of the year, 55% gas and 45% oil.
Venture's strategy has been successful and its growth strong: 10 years ago output averaged only 200 boe/d. The firm now operates 18 producing fields in the central and southern North Sea and has interests in three others. It holds a large portfolio of undeveloped discoveries and exploration prospects – almost all in the gas-prone central and southern provinces, and most of them operated and 100%-owned.
The secret, the firm says, has been to keep itself free of "large overheads and bureaucratic backlogs" and to avoid "the huge expenses and risks associated with exploration". Most of the assets it has acquired have been proved by previous operators, but were too small for a large firm to develop, or did not fit in with a new corporate strategy, or were in production and needing rehabilitation.
Fairfield Energy is another new operator with assets formerly operated by Shell. The company – UK-based, set up in 2005 and backed by private-equity investors led by Warburg Pincus – purchased the Dunlin, Dunlin Southwest, Osprey and Merlin fields in May last year, in a 70:30 venture with Mitsubishi. Fairfield awarded a field-lifetime duty-holder contract for the cluster to Amec and drew up plans aimed at keeping the fields in production for another 10-15 years.
In May, Fairfield and Mitsubishi made another acquisition from Shell and partners, buying acreage adjacent to Dunlin holding two undeveloped finds. The finds are potential low-cost tie-backs to the Dunlin platform and there are other prospects that might be tapped by wells drilled from the platform. The venture also holds two part-blocks east of Dunlin, won in the 25th licensing round.
On its own, Fairfield acquired an undeveloped southern North Sea gasfield, Clipper South, from Shell and ExxonMobil early last year – but has brought in a larger partner for the development project. In May, RWE Dea farmed-in to earn a 50% share and will take over the operatorship. A development plan, using a platform with up to six horizontal multi-fractured wells, has been prepared and first gas is expected in 2011.
The small operators emphasise their risk-minimisation strategies: with relatively low levels of production and significant debt, they cannot afford unsuccessful exploration wells. Operations in the most mature parts of the North Sea are preferred, where existing seismic surveys can be re-processed and re-analysed and, sometimes, laterals can be drilled out of existing well-bores.
The most notable failure – Oilexco North Sea, which the firm's Canadian parent took to the administrators at the beginning of the year (PE 2/09 p29) – also happened to be the most active explorer in the UK North Sea recently, measured by the number of exploration and appraisal wells drilled, although many were sidetracks. The firm had achieved exploration successes, but its output had declined to 11,951 b/d in the third-quarter of last year as a result of long-running maintenance work on the Balmoral production facility, while development commitments continued and credit was drying up.
Premier Oil paid $0.501bn for the subsidiary in May and celebrated in August when the Oilexco-developed and wholly owned Shelley field came on stream. The acquisition lifted Premier's total of operated UK producing fields to seven and raised its UK production to a forecast 2009 average of 20,000 boe/d.
Oilexco also provided Premier with some promising development prospects. A well is to be drilled in the mapped northern extension of the Bugle structure – a potential development – in the first quarter of next year, and the Moth gas and condensate structure is due for further appraisal. Development concepts for the Huntington light-crude field are being studied.
Cost-cutting is the challenge
THE ESCALATING cost of offshore hardware and services is the main threat to UK North Sea exploration and production activity levels, according to leading operators. Oil and gas prices have halved from their 2008 peaks, but suppliers have not adjusted to the new environment.
Statistics from the government's Department of Energy and Climate Change point to a sharp slow-down in North Sea activity this year, after a relatively busy 2008. Only nine exploration wells were drilled in the first six months, compared with 44 for the whole of 2008, while only 20 appraisal wells were completed, down from 61 last year. By early September, only six oil and gas development projects had started, compared with 22 in the whole of last year.
A disincentive for investment
Recent wildly swinging oil and gas prices are a disincentive for investment, because companies often use the low points in their project economics. Although the price of the UK's Brent Blend averaged $97 a barrel last year, there was a high of over $140/b in July and a low of under $40/b in December, followed by a climb to over $70/b this summer. The UK's day-ahead gas price peaked last summer at over £1.00 a therm, but declined in the winter to £0.60 a therm and then to very low levels this summer.
According to Oil & Gas UK (OGUK), the offshore producers' and suppliers' association, two-thirds of new oil developments in the UK North Sea need a price of at least $50/b to justify the investment. Gas developments are particularly challenged, OGUK says, because gas typically trades at about two-thirds of the price of oil on an energy-equivalent basis, while gas projects cost as much as, or more than, oil projects.
In its 2009 Economic Report, published in July, OGUK says the cost of developing a barrel of oil or the energy-equivalent of gas increased six-fold between 2001 and 2008 – far exceeding the rises in oil and gas prices (see Figure 1). Over the same years, operating costs per barrel or equivalent more than doubled.
The tax take also increased, twice, over the period, and now stands at 50% at the margin for fields developed after 1993 and 75% for earlier fields. OGUK argues that a progressive reduction of the tax burden is needed to sustain investment, now that the average size of new discoveries is small.
New-field allowances introduced in this spring's budget – intended to encourage the development of small fields, ultra high-pressure, high-temperature fields and ultra heavy-crude fields – are a "modest step", which might accelerate the development of "one or two" fields, OGUK says.