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Norway's Arctic development will take time and money

Norway's Arctic experience shows that development in the High North will take time - and money

In 1896, on his return to Norway after an ill-fated three-year quest to reach the geographical North Pole, the country's pioneering polar explorer Fridtjof Nansen said: "The difficult is what takes a little time; the impossible is what takes a little longer."

Almost 120 years after his Arctic expedition, Nansen's statement could apply equally to exploration and production in Norway's High North. While resources totalling an estimated 8 billion barrels of oil equivalent (boe) lie in Norway's Barents Sea play alone, Norway's slow steps in the High North are proof that as well as deep pockets, a thorough understanding of the operational environment and technological expertise, companies hoping to operate in this new frontier require vast reserves of patience.

Unlike fellow Arctic producers Russia or Alaska, Norway has no onshore production. The country's hydrocarbon plays lie offshore, a geographical reality that has compelled companies active in Norway's upstream to specialise in harsh environment, subsea and deep-water technologies.

Innovation

This expertise, born of necessity, has proved key as state-controlled Statoil and other players push into the Arctic. And, with the Norwegian Petroleum Directorate estimating that the country's Arctic hosts total reserves in the region of 18.7bn boe, building on that expertise and adapting existing technologies to polar conditions will prove vital if large-scale development is ever to become reality.

But this will take time, a fact Statoil readily acknowledges. Rúni Hansen, vice president of Statoil's Arctic unit, stressed that Arctic exploration operates on a far longer time horizon than activity in more southerly waters, telling Petroleum Economist: "There is no race for the Arctic. We cannot go faster than the technology allows."

Statoil, Hansen says, advocates a step-by-step approach to unlocking the Arctic. While expense is a factor informing this choice, he adds: "(We need to better) understand the environment and ensure the technological solutions we use are fit for purpose. The Arctic is highly diverse, with many different challenges."

The Norwegian company, he explains, approaches the Arctic as a three-step play: the workable, the stretch and the extreme."The workable category covers completely ice-free areas - the Barents and Canada's east coast, for example. We have lots of experience here," Hansen says, pointing to the 100 wells drilled so far in the Barents. The stretch Arctic covers those regions which are seasonally ice-free: the Sea of Okhotsk, the Beaufort Sea and western Greenland, for example. "The key here is ice management," Hansen says. He adds that while these plays are more challenging, and exploration and development will require more sophisticated and robust technologies, the difficulties the stretch Arctic presents lie within the reach of the industry's capabilities.

The third category is the extreme Arctic, covering those parts of the region which are ice-bound year-round. "This is a distant, future option," Hansen says. But even in the workable and stretch Arctic plays, exploration and production will take time. Speaking at an Arctic conference in 2013, the company's exploration chief, Tim Dodson, said Statoil did not envisage production from many Arctic areas before 2030 at the earliest - perhaps even as late as 2050. 

It is not just developing suitable technology that is slowing activity in the once-hotly touted Arctic plays. Exploration costs alone are giving many companies pause for thought. A shortage of suitable harsh-environment drilling rigs has seen day rates climb to more than $600,000. Add to this the costs of a second drilling unit, sometimes required to meet tight environmental and safety requirements, plus the charter of support vessels, then factor in a possible 45-to-60 day campaign, and a wildcat well becomes high impact in more ways than one. Dodson said: "There's almost no prospectivity on the planet that can support drilling exploration wells (that cost) half a billion dollars each. And that's what we're talking about for some of these wells."

It's not just that exploration carries a high price - the development costs in Norway's workable Arctic can be equally steep. Take for example, the Snøhvit gasfield, which lies in the southern Barents Sea, about 140 km offshore Hammerfest. Snøhvit feeds the only liquefied natural gas (LNG) plant in operation north of the Arctic Circle. Yet it took 23 years - from discovery in 1984 to first gas in 2007 - and an estimated $8bn for Statoil to bring the 193bn cubic metre gasfield on stream.

The high price reflects not just the pioneering nature of the project - Snøhvit was one of the world's first major subsea developments; it was also the first development in Norway's remote northern waters, requiring major investment in plant, facilities and infrastructure. But technical problems - particularly at the Melkøya LNG plant, to which output is piped - environmental and regulatory issues have taken the shine off what should have been a triumph for Statoil.

Plans to expand the plant's capacity have been put on hold, with Statoil and its partners saying that the known gas discoveries within tie-back distance of Snøhvit 's facilities do not provide sufficient basis for further capacity expansion. Three further development phases envisaged in the original Snøhvit development plan have also been shelved for now. The Goliat and Johan Castberg oilfield projects, also in the Norwegian Barents, throw the Norwegian workable Arctic's project economics into even starker relief.

The difficulties Statoil experienced at Snøhvit are mirrored in part at the Eni-operated Goliat oilfield, in which Statoil holds a stake. Thanks to a combination of regulatory difficulties, shipyard delays, compliance issues and rising commodities costs, Eni says Goliat, discovered in 2000 and originally due on stream in 2013, is now expected to pump first oil in the fourth quarter of 2014. Insiders expect this to slip further, however, perhaps well into 2015. In 2009, development costs for the 174m barrel field, which will be the first producing oilfield in the Barents, were estimated at $4.34bn. At that time, the project's break-even price was $50 a barrel. However, the latest official estimate, released late last year, now put costs at around $6.3bn. This implies that in order to turn a profit, Eni needs to see a similar increase in price per barrel - roughly 45% - to $72.50/b.

Escalating costs also underpin Statoil's decision to delay and review the development of Johan Castberg, formerly known as Skrugard and Havis. The development, which holds an estimated 400m to 600m barrels of oil, was pencilled in for a 2018 start-up. A revised date has not yet been made public. The Norwegian energy ministry said the project's break-even price has risen from $64/b to $81/b, saying higher costs have added $10/b to the break-even while changes to the Norwegian tax regime add a further $7/b.

Castberg is one of the biggest finds made offshore Norway in the past decade, and was touted as the development which would open the Barents as an oil province. Calling the increase a warning about cost development in the sector, Trond Omdal, an analyst with Arctic Securities, told the Wall Street Journal: "When a field that contains 500m barrels isn't profitable, it's worrisome."

High costs

E&P costs for players in the Norwegian sector are eye-watering, and, so far, exploration results have not been as good as hoped. Last year, of the 100 wells drilled in the Norwegian Arctic, just six were finds and only two of those are likely to be developed. Still, this has not dissuaded companies from wanting to gain a foothold in the play. The 23rd licensing round, launched in February, covers blocks nominated by explorers. Oil firms nominated 160 blocks; the oil ministry is offering 61. Of those, 54 are in the Arctic: 34 in the southeast sector of the Barents, near the maritime border with Russia, and 20 elsewhere in the Barents. The oil ministry has said that interest in the round, even at this early stage, is high.

Statoil, too, is maintaining its Arctic profile. This year, it is planning to spud at least two wells at the Atlantis and Apollo prospects, in the Hoop region, about 400 km north of the North Cape. In 2013, OMV and Statoil hit hydrocarbons at Wisting Central, also in the Hoop play. While the company is hoping to make finds, Dodson earlier referred to the Hoop campaign as "laboratory" and "stepping stones for future drilling".

Dodson is under no illusions about the company's Arctic plans. But he believes long-term collaboration and information-sharing is vital for the energy industry's future in the Arctic. "What we are facing," he says, "is an industrial challenge, not a company challenge. "If one of us fails, we all fail." 

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