In his previous incarnation as a globe-trotting oilman based in south-east Asia, Simon Lockett concentrated on lucrative oil plays in exotic locations.
Now chief executive of Premier Oil, Mr Lockett has traded gin and tonics in Jakarta for kippers in Aberdeen, transforming a part of its portfolio once considered as being in terminal decline: the North Sea.
“It’s a second wind. Four years ago we looked at the business and realised we needed to turn it round – we had development projects in Asia and were trying to balance it out. The North Sea is now part of that, those assets will help us double our production,” says Mr Lockett.
Several factors conspire in what has been dubbed as the North Sea’s “renaissance”. First, oil prices. With crude oil trading at $70-$85 a barrel, smaller fields passed over by larger oil companies become much more viable. As Peter Hitchens, an oil analyst at Panmure Gordon says: “Suddenly, people realised that you can still make a lot of money with a 20m or 30m barrel field.”
Second is political stability. While any chief executive will grumble about the UK government’s 50 per cent tax rate on oil operators, the political regime is more predictable than operations in Africa or Asia.
Third, the infrastructure: it is already there. Keith Morris, an analyst at Evolution Securities, says: “A decade ago when the oil price wasn’t so good lots of majors went off to west Africa or Brazil, leaving the small discoveries to the independents.
“But the reward is still there – now if you find 50m barrels there’s enough infrastructure there to make that economic. So it’s a combination of things that has renewed interest.”
A second boom in the North Sea has been predicted for some time. In 2009 the UK portion produced more than 2.3m barrels of oil and gas equivalent per day (boe/d). According to UK Oil and Gas, the industry lobby group, 24bn boe have yet to be recovered. But as the majors such as BP and Shell shed their assets in the area, public attention shifted to large, untapped discoveries in Congo and Kazakhstan.
Recent foreign interest in the North Sea has thrust the area into the limelight, a fact borne out by the frenetic mergers and acquisitions activity over the past few months. Most prominent among these was Korea National Oil Corporation’s £1.87bn hostile bid for Dana Petroleum.
In August, KazMunaiGas, Kazakhstan’s state-owned oil company, followed suit, making its first foray abroad by spending $30m (£19m) on a 35 per cent stake in BG Group’s White Bear prospect in the central North Sea. Last month Centrica, the owner of British Gas, spent £144m – on top of £1.3bn last year – expanding its North Sea assets.
Pipeline peeves
It was after the eighth attempt that Bill Transier decided he had endured enough, writes Christopher Thompson.
Since January 2009 the chief executive of Endeavour, a London-listed independent oil explorer, had been trying to negotiate pipeline access for oil from the company’s Rochelle field in the central North Sea.
The problem was that the nearest platform needed to bring the oil onshore was owned by a consortium of five companies, including US oil group Exxon, which demanded hefty fees.
“We tried to negotiate for a year with them and they wouldn’t even talk to us – they think that they can squeeze smaller companies for rent. They wanted almost four times what we offered, which would make [the operation] uneconomic for us,” Mr Transier said.
It is a common complaint. Since they flooded the North Sea over the past decade, several independent explorers have complained to national regulators, accusing majors of using their monopoly over infrastructure to price competitors out of the market.
Tussles over rights to the North Sea’s ageing pipes and platforms has in turn brought a more important issue to light: looming decommissioning costs of idle infrastructure. According to research by Deloitte and Douglas-Westwood the cost of retiring the 260-plus offshore oil and gas platforms on the UK portion of the North Sea could be more than $30bn (£19bn) over the next 30 years.
That is a boon for oil service companies and a major incentive for explorers to use the infrastructure available before it is scrapped.
If disputes over access cannot be resolved, then everyone loses. In Endeavour’s case, the company claims that oil from its Rochelle field would defer the decommissioning of its nearest platform by 10 years.
“What the UK government needs to do is adopt a ‘common carrier’ approach,” said Mr Transier.
Premier Oil’s North Sea transformation culminated in the Catcher discovery in June – an estimated 300m barrel field of the kind presumed to have long been pumped dry by the majors and the biggest find for nearly a decade. Premier shares Catcher with Encore, Wintershall, Nautical Petroleum and Agora Oil – all typical of the fleet-footed scavenger companies that have been snapping up unwanted assets from the majors in recent years.
Amjad Bseisu, chief executive of EnQuest, epitomises the strategy: “We take on fields too small for the majors, buying into existing fields which have been in production for a long time and optimise the assets.”
That has let to greater consolidation. In August Aim-listed Stratic was bought by EnQuest in a $45m deal. That was done as part of plans to invest $1bn on developing its North Sea assets in the next five years, which it hopes will boost production there to 21,300 boe/d by 2011.
Ithaca Energy, which produces 5,000 boe/d from its North Sea fields, bought GDF Suez’s North Sea assets in August and recently secured a $140m lending facility for more bolt-ons.
“Both types of companies, such as EnQuest and KNOC, are willing to snap up assets that are out there because they see growth in the North Sea. That will accelerate. There will be lots of building up, there is room for manoeuvre, even for the smaller companies,” says Mr Hitchens.
Although often referred to in the singular, there are actually two distinct North Seas. The central, southern and northern sea is well–trodden and the focus of recent acquisitions by the independents. The other sea, west of the Shetland Islands, is characterised by extreme environmental conditions and water depths of 600m or more. It is also where a fifth of the UK’s remaining oil and gas reserves – the equivalent of 2.1bn barrels of oil and gas – are believed to lie.
In January, the UK government announced a tax allowance worth up to £160m a field to catalyse development, such as Chevron’s giant Rosebank oil field – predicted to eventually produce 75,000 b/d.
In March, Total received regulatory approval for its Laggan and Tormore gas fields, a £2bn development to take gas to a processing plant on Shetland by 2014 and then into the UK grid.
But with greater promise comes greater risk, and with the pall of the Macondo Gulf of Mexico disaster casting a shadow over the offshore industry, the area west of Shetland has attracted particular attention. Soon after the BP disaster Tim Yeo MP, head of parliament’s energy select committee, said “serious questions needed to be asked” about the safety of deep water drilling there.
Last week, the government gave Chevron the go-ahead to start drilling a deep water well off Shetland.
Politically the carrot-and-stick approach is likely to continue, with concerns over safety being tempered by the realisation that heavy investment is needed to squeeze out the North Sea’s remaining resources.
Richard Rose, an analyst at Oriel Securities, says: “It’s a case of managing the decline curve – we will have an oil industry in 10 years but will it be producing 1.5m boe/d or 800,000 boe/d? That’s what the new investment is driving towards.”