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Norway winds down

Fresh developments in the Arctic promise new production, but enthusiasm for fresh licenses has waned

A decline in applications for production licenses in Norway's latest oil and gas auction suggests that appetite for fresh exploration on the Norwegian continental shelf may have passed its peak. However, existing offshore discoveries are still being converted into substantial developments.

The number of companies who applied for acreage in the 24th oil and gas licensing round plummeted to just 11, down from 26 in the previous round.

Applicants this time included Statoil and mid-sized Norway specialists Aker BP and Lundin, as well as Shell, Centrica, OMV, Wintershall and Kuwait's Kufpec. Also in the list was Rosneft's Norwegian subsidiary, RN Nordic, which together with a proposed deal under which Gazprom would take a 38.5% stake in OMV's Norwegian assets, indicates Russian firms are keen to get a toehold in Arctic waters.

On offer were 102 exploration blocks, of which 93 were in the Barents Sea and nine in the Norwegian Sea. The Norwegian Petroleum Directorate said interest was greatest in the northwest Barents Sea. The government hopes this frontier area can produce chunky discoveries to bolster sagging reserves from the Norwegian North Sea. Blocks are due to be awarded by mid-2018.

Some notable exploratory drilling failures by Lundin and Statoil over the past year may have persuaded companies to adopt a more cautious stance in the current licensing round. But another important factor is the technically more complex—and costlier—nature of exploring in the further extremities of the Barents Sea. This restricts the pool of likely participants to those with deeper pockets. With the majors now downscaling exploration—there's no Eni or Total on the list—the more sizeable local players must fill the niche.

As in the UK, further south in the Norwegian North Sea the game is different, with smaller firms likely to play a more significant role in seeking to extend the life of mature fields in which the majors have lost interest. The use of existing infrastructure means they can cap development costs more readily.

Slimmer Castberg plan

Development of existing finds in the Barents Sea took another step forward in December when Statoil unveiled its development plan for the Johan Castberg field, which is scheduled to come onstream in 2022. It's a much lower-cost plan than had originally been envisaged, reflecting the need to make it viable at $60 a barrel oil.

"Statoil has managed to bring down the breakeven price to make it a profitable project," said Espen Erlingsen, an analyst at Oslo-based consultancy Rystad Energy. "Back in 2013, the company was talking about $80 a barrel as a breakeven price—now it's below $35/b. In that field, they have achieved a lot of cost savings and proved it commercial."

Johan Castberg is still expected to cost around $6bn to extract recoverable resources estimated at 450-650m barrels of oil equivalent, according to Statoil.

With majors downscaling, local players must fill the niche

That's down from the $12bn capital spending or so originally envisaged for the project.

The savings have been achieved, in part, due to the lower cost of oilfield services compared to five years ago and efficiency improvements. Also, the development was simplified into one based on a floating production, storage and offloading facility, from which oil will be transferred to tankers.

Statoil, which has a 50% stake in the development, originally planned to run a pipeline from the field to a stand-alone oil terminal on the Veidnes peninsula. But it has deferred a decision on whether to invest in that until 2019, pending further talks with its partners—Eni (30%) and Norwegian state-owned Petoro (20%)—and other potential users.

Statoil has signed contracts worth some $0.5bn with Aker Solutions, both for construction of Johan Castberg's sub-sea system, and engineering-and-procurement management.

The company also submitted its development plan for the expansion of its marginal Snorre field for approval, designed to increase recovery by almost 200m barrels. Contracts worth up to $1.1bn for that project were signed. At the same time, contracts worth up to NOK9bn ($1bn) for the Snorre project were awarded to companies including Subsea 7 and TechnipFMC.

Aker BP expands

Meanwhile, Aker BP, the acquisitive company 40% controlled by Kjell Inge Røkke, has cleared the path towards further investment in its growing portfolio of Norwegian assets: its $2bn purchase of the Norwegian operations of US firm Hess was completed in late December 2017. Hess was the majority shareholder in two North Sea fields, Valhall (64.5%) and Hod (62.5%), where it was partnered by Aker BP. Hess Norge's share of production from the Valhall and Hod fields was some 24,000 barrels of oil equivalent a day.

The deal enables Hess to fulfil its ambitions to exit the Norwegian offshore, while clearing the way for Aker BP to take control of field development. In early December, Aker BP sold a 10% stake in the two fields to private-equity-backed Pandion Energy for an undisclosed amount to help finance the development. Also in December, Aker BP submitted a field development proposal to boost output from the Valhall field, with first oil expected in late 2019. The company says Valhall and Hod production since operations started in 1982 passed a cumulative 1bn boe in early 2017, with a target of producing a further 0.5bn boe.

The Aker BP-Hess deal is typical of the maturing Norwegian and UK oil provinces, where majors are bowing out of operatorships to focus on more lucrative opportunities elsewhere in the world.

Aker BP is itself a product of BP's desire to offload its Norwegian acreage to a keener local player, while retaining a 30% stake in the combined company to provide support. However, the deal also gave BP access to output from the giant Johan Svedrup field in the North Sea, which is estimated to contain recoverable reserves of up to 3bn boe. Aker BP has an 11.6% interest in the field.

In the UK, BP has also participated in deal structures intended to smooth the path towards relinquishing operatorship, notably its recent sale of maturing fields to minnow Serica in November 2017, which is based around deferred purchase payments.

Infrastructure hub?

Scope for more offshore projects on the scale of Johan Castberg or Johan Svedrup may be limited, although a big discovery could change that. Johan Castberg is also likely to act as a spur to other Barents Sea projects, such as Lundin's discoveries in the Alta and Gohta fields to the south of Castberg, as well as OMV's Wisting field to the northeast. OMV has said this could hold resources in-place of over 1bn boe.

All could potentially benefit from infrastructure being developed for Johan Castberg, with a supply base at Hammerfest. Any future output from some or all of these fields could be piped to Castberg's proposed onshore oil terminal, if that gets built. Eni's troubled Goliat project, which is closer to shore, could also potentially benefit from a new oil terminal.

2022—Johan Castberg's scheduled start-up date

Goliat's is the development model that others will be keen to avoid—and probably will, given the radical change in the industry's views of costs, complexity and risk since its inception.

After years of cost overruns and delays during the development phase of a project conceived before the oil-price crash, Goliat—where the first discovery was made in 2000—finally started production in April 2016. Since then the field, with capacity to produce around 100,000 barrels a day, has been beset by production stoppages and safety and maintenance incidents, culminating in a shutdown of more than two months in late 2017 for investigations at the behest of the Norwegian Petroleum Safety Authority. Production resumed in mid-December, following modifications to the platform's electrical system and planned maintenance, according to Eni.

Analysts question whether the development can be profitable at $60 a barrel oil, especially as production is forecast to plateau within the first two years of operation, before declining. But Eni contends that planned drilling of new production and appraisal wells in 2018 promises to add to volumes and improve the development's economics.

Arctic exploration risks

Looming over the industry's decision-making process regarding long-term Norwegian investments are concerns over the longevity of the country's offshore industry. The companies say they remain positive and the government is fully supportive of the industry; but maintaining overall oil and gas production levels is dependent on relatively costly Arctic developments, where drilling remains controversial. Greenpeace and other non-governmental organisations took the government to court over Arctic drilling in a case heard in November. They claimed that drilling in environmentally sensitive parts of the region violated the Norwegian constitution and contravened the Paris climate change agreement.

"Winning this case—having new oil licenses in the Arctic ruled invalid—would keep millions of oil barrels in the ground," Trolls Glowed, head of Greenpeace Norway, said, adding that the country "risks losing billions by investing in these oilfields".

The NGOs have also pointed to a proposal in November by Norway's sovereign wealth fund—the world's largest—that it should drop oil and gas stocks from its benchmark index. This is seen as an indication of the fund's belief that the country's hydrocarbons industry has little future. At that time, oil and gas shares accounted for about 6% of the index, with a value of more than $35bn.

Norway's central bank said the move was intended to reduce exposure to volatile oil prices, and to hydrocarbons stocks in general—which have tended to underperform in the global equities market recently—rather than being based on any view of the Norwegian industry in particular.

Regardless of whether or not the court case verdict, expected in early 2018, goes in favour of the NGOs, the oil companies know their Arctic activities are going to come under intense scrutiny.

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