Norwegian, UK production outlooks stabilize on new development, cost cutting efforts
In Norway and the UK, there is a recognition that a growing ecosystem of companies of many shapes and sizes, coupled with successful cost-cutting efforts since 2014, are helping to maximize crude oil output and manage long-term production decline. In the UK, the establishment of the Oil and Gas Authority as a new industry regulator has replaced the old laissez-faire approach to production with a more rigorous, unified system. By contrast, state-centric Norway has begun to benefit from a surge in private equity investment and overall growth in the number of independent companies outside of the umbrella of state-owned oil and gas major Statoil.
This optimism has ultimately proved to be well-founded, with oil production stablizing in both countries, following decades of overall decline, and Norway still expecting a big boost from two large-scale projects, the Johan Sverdrup and Johan Castberg fields.
The UK, in particular, is expected to see production stabilize at 1 million b/d through the end of this decade, thanks in large part to the development of new fields like Catcher, Kraken and Western Isles, and the refurbishment of the Clair and Schiehallion fields west of the Shetland Islands. Together, these five fields are set to produce some 380,000 b/d at peak production.
Crude production in the North Sea
Sweet crude field distribution NWE
Forties shutdown and infrastructure concerns
But the UK’s reliance on ageing infrastructure, some of which passed from BP to smaller North Sea companies in 2017, is a concern, both in terms of immediate operations and long-term exploration. The shutdown of nearly half the UK’s oil output due to a hairline fracture in the Forties pipeline in December raised concerns about the long-term future of the North Sea oil industry – but there remains optimism in many quarters that investment decisions and productivity gains made in recent years will secure the sector’s medium-term future.
For participants in the Northwest European markets, the unexpected shutdown of the Forties Pipeline system in December could be a harbinger of more problems to come as years of limited investment in infrastructure begin to bite. It remains unclear whether the shutdown signals more such problems ahead. Ineos’ response to the outage was swift, with production ultimately resuming ahead of schedule and running smoothly ever since. But Ineos’ experience with FPS could add to worries among exploration companies looking to invest in and prolong North Sea production. If the future of production – particularly in the UK – lies with the extraction of resources from multiple small accumulations of oil and gas, concerns are not unfounded that a pro table business model is not viable if the legacy pipelines used to transport these resources are removed from service.
Industry optimists have recently pointed to a spate of deals in which major companies BP and Shell have sold assets in their North Sea heartland to smaller, dedicated players. The assumption is the recipients, with a narrower range of options, will be hungrier to optimize these operations. But there are reasons to be skeptical. BP’s sale of its Sullom Voe terminal to the much smaller upstream EnQuest helped to raise the latter’s profile as it brought the Kraken ultra-heavy oil field on stream. However, financial constraints then forced EnQuest to cut spending on its existing assets, resulting in a 13% drop in its overall output in the first 10 months of 2017.
Shell’s recent sale of mature UK assets to private equity-backed Chrysaor for $3 billion-$3.8 billion was widely seen as a vote of confidence in the North Sea, partly because it suggested private equity investors are ready to accept slower returns, even as the price of the sale raised eyebrows.
West of Shetland key to UK oil future
Increasingly, the UK’s far-northern Shetland Islands are beginning to epitomize both the fears and hopes surrounding UK oil production. BP’s decision to hand over operations of the 40-year-old Shetland oil terminal at Sullom Voe to the much smaller, independent EnQuest in 2017 unnerved many in the industry, raising questions about the role that the global oil majors expect to play in upstream production in the coming years. EnQuest’s own financial struggles over the last several years of low oil prices are seen as evidence that not everything can be left to the small players.
Sullom Voe itself has seen its central role as a major processor of North Sea crude drop dramatically over the last several decades. Once responsible for processing some 1.5 million b/d of crude in the mid-1980s, processing dropped to just 100,000 b/d in recent years. Many companies working in the west of Shetland oil province have elected to bypass Sullom Voe entirely, opting to ship directly to market. Nowhere is this more apparent than with BP and Shell’s newly redeveloped Schiehallion field, with crude now shipped directly to Rotterdam rather than through Sullom Voe.
The harsh conditions in the cold Atlantic have caused their own problems with development, adding to the costs of further exploration in the region. Chevron and partners have repeatedly delayed the 300 million barrel Rosebank oil project, seen by some as a step too far. Independent Premier Oil’s Solan field, a $2 billion project that came on stream last year, has also under-performed, producing just 7,000 b/d in the rst half of 2017.
And yet, even as the majors have shed smaller assets they now voice confidence in the UK’s ability to stay competitive, with new discoveries west of Shetland making waves in recent years. Hurricane Energy, for example, hopes to unlock hundreds of millions of barrels or more from its Lancaster oil discovery despite the uncertainty about the flow properties of the unusual “fractured basement” development. The company is targeting initial output of just 17,000 b/d, with production starting in 2019.
Also waiting in the wings is the Cambo oil project, operated by private equity-backed Siccar Point Energy. Located in the same geological structure as Rosebank, Cambo is thought to hold over 100 million barrels of crude oil, and Siccar Point’s chief executive Jonathan Roger suggests that these new projects could keep the majors active in field development west of Shetland. He told S&P Global Platts in September he expected Chevron to take a final investment decision on Rosebank, in which Siccar Point holds a 20% stake, in 2019.
“You’ve got to have pretty deep pockets… I don’t think there will be an over-abundance of small companies coming in to the West of Shetlands because it’s very much the majors’ heartland, that’s where they want to be – the BPs, the Shells,” Roger said. “It’s still a key area of focus for the big guys.” Shell chief executive Ben van Beurden told journalists on February 1 that, “There’s a lot of rejuvenation going on in the North Sea.” It followed Shell’s decision in January to go ahead with Penguins, a $1 billion project expected to produce some 45,000 boe/d of oil and gas. “We remain committed to the North Sea and we see more opportunity to grow,” he said.
Norway remains bullish
While production of the grades which constitute the current Dated Brent benchmark is expected to decline from 2019 onwards, overall North Sea crude production is forecast to remain resilient for much of the 2020-30 period, with the bulk of new production accounted for by Norway.
The discovery at the start of the decade of the Johan Sverdrup field, with resources of between 1.9 and 3 billion barrels, has completely altered the North Sea landscape in the medium term, especially as the fields lie in the industry’s heartland and within easy reach of the supply chain and regional refineries. Johan Sverdrup is currently forecast to produce 440,000 b/d in its initial phase beginning in late-2019, with production climbing rising to 660,000 b/d in the first-half of the 2020s. Production of this magnitude will dwarf any other single production stream in the North Sea, even as Norway looks to refurbish legacy fields Yme, Njord and Snorre.
Exploration and development in the Barents Sea along the country’s northwest coast has also picked up pace, though – the large Johan Castberg discovery aside – finds have largely been of a smaller scale. Norway’s northern-most producing field Goliat came on line in March 2016 with development being led by Italian major ENI. The field has a production capacity of 100,000 b/d, but has been beset by technical and safety problems that have kept output shut for much of the time.
By far the largest project in the Barents Sea is Johan Castberg, which is estimated to hold some 400 million-650 million barrels of distillate-rich crude oil, but the project has suffered setbacks around how to best develop infrastructure around the new field. “The Barents Sea continues to frustrate… [It] lacks a big, reliable, widely distributed reservoir system,” Westwood Global Energy research president Keith Myers said at the PROSPEX event. Despite such difficulties, in the medium term at least the prospects for Norway’s oil industry look reasonably assured. In an update in July the Norwegian Petroleum Directorate reported that six oil and gas discoveries had been made in the first six months, and six projects approved for development. “The activity level on the Norwegian shelf is high,” the NPD said.
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