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The return of cautious optimism in the North Sea

The UK’s North Sea hub, braced for production declines, has received a boost from new investments and revived interest from the supermajors

There's more optimism around Aberdeen, the main centre for the North Sea oil and gas industry, than there has been for some years. Offshore activity is picking up, albeit from a low base, and the city is slowly filling up again. Oil company executives can't always get rooms in their favourite hotels these days, and taxi drivers—those trusty barometers of economic health—say they're the busiest they've been since the oil-price crash sent industry spending into a nosedive. There's still plenty of vacant work space around, but the signs are positive.

Perhaps the clearest evidence of a turnaround in the fortunes of the UK Continental Shelf (UKCS) was the greater-than-expected interest shown in the recent 30th Offshore Licensing Round, the results of which were announced by the UK's Oil and Gas Authority (OGA) in late May. The round was focused on acreage close to existing developments, to entice low-cost developments via tiebacks to existing infrastructure.

That attracted the expected interest from smaller oil companies. The phenomenon of minnows grabbing exploration and production assets from majors keen to divest their more marginal blocks in the maturing North Sea is now well established.

More surprising to some was the interest shown in the round by those majors which, over recent years, have generally been trying to divest themselves of all but their prime pieces of UKCS acreage. Typical of that trend was Chrysaor's purchase of a portfolio of assets from Shell, completed in November 2017, while BP is in the process of selling its stakes in the Bruce Keith and Rhum (BKR) fields in the North Sea to Serica Energy.

In the 30th licensing round, BP, ConocoPhillips, Equinor-formerly Statoil-and Shell were among those offering firm commitments to drill, along with Chrysaor, i3 Energy and Independent Oil and Gas. At the other end of the scale, the round also attracted seven North Sea debutants in the shape of Carrick Resources, Marque Oil & Gas, Mytilus, Petrostars SPX, Soliton Resources, Spark Exploration and Tangram Energy.

This diversity of firms awarded licenses and the relatively high interest levels prompted Andy Samuel, the OGA's chief executive to declare that "the UKCS is back", and assert that "big questions facing the basin have been answered in this round".

Kevin Swann, a regional analyst at consultancy Wood Mackenzie, said the OGA had good reason to play up the outcome. "If you look at the number of licenses and committed wells, then we are back to around the levels of the 28th round in 2014. Given this was an exclusively mature round, it's been a pretty successful one and I'm not surprised they're so pleased with it," he said.

It's the oil price, stupid

One obvious reason for the uptick in interest was the improving oil price. While it wasn't at mid-2018 levels, it had already started to rally when companies put in their applications towards the end of 2017, making near-field developments look more profitable. But the industry's efforts to drive down costs, combined with more flexible licensing terms and the OGA's efforts to make block data more easily available to applicants, also helped, according to Swann.

Mitch Flegg, chief executive of Serica Energy—one of the new wave of smaller North Sea players—was more circumspect. He told Petroleum Economist in Aberdeen that the license round response was encouraging. But its launch, at a time when companies were more cautious about future investments, prevented it being as successful as it might have been.

"The timing of the 30th round was unfortunate," he said. "The feeling around the industry has changed a lot in the last six months and I think if the applications had been going in today, it would have been different. But I think, in the circumstances, there was a good amount of enthusiasm for the round."

All creatures great and small

The mix of industry leviathans and minnows still prepared to take the plunge in UK offshore is striking.

For example, in West of Shetland, operator BP is expanding its activities in the redeveloped Greater Schiehallion area, after saying in April it would develop the Alligin field there, as well as the Vorlich field in the North Sea. Both are "small pool" developments that tie back to existing fields and could add around 30,000 barrels of oil equivalent a day to UK output.

Meanwhile, Siccar Point Energy (SPE), one of the region's relative newcomers, is preparing to drill the Lyon prospect on its acreage in the outlying Northern Gas Area to the north of Shetland, which is estimated to hold 1-3 trillion cubic feet of gas.

"It's a big-impact exploration well, and while there's never a guarantee with that, we're pretty excited about it," Jonathan Roger, SPE's chief executive, told Petroleum Economist at the company's new headquarters in western Aberdeen.

Bargain-price rigs

Roger said exploration success with Lyon would help de-risk further exploration in the area. It could lead to the development of a gas-hub development similar to that created for the Total-operated Laggan-Tormore development, based around sub-sea infrastructure and pipelines running to a gas plant on Shetland. It could also pave the way for smaller gas discoveries close to Lyon, to be tied back to a new hub on that field.

SPE consolidated its position in West of Shetland in the 30th Licensing Round, adding to its acreage in the Greater Cambo Area. It was awarded a number of blocks there in a 50/50 venture with Shell, and one as 100% license holder. Shell farmed in to Siccar's existing Cambo acreage as a minority shareholder earlier this year. SPE started drilling a final appraisal well on Cambo in May, with results expected later in the year.

SPE's focus on near-frontier, long-lifetime developments around Shetland—including an 11.75% stake in BP's Greater Schiehallion development—demonstrates how the low-oil-price environment of recent years has sometimes worked in favour of the industry's minnows, even away from the more obvious low-cost plays. Smaller firms that would have had little chance of getting a foothold in frontier acreage with $100-plus oil five years ago are now significant players. They've acquired stakes at knock-down prices and can plan ambitious drilling campaigns using low-cost rigs.

Industry executives are aware that time is of the essence, as rig rates and other supply-chain costs start to edge higher after the slump. The current era may come to be seen as something of a late golden age of affordable E&P in the North Sea, as capital expenditure picks up, but oilfield services costs remain relatively low.

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