The Snohovit LNG plant in Hammerfest, Norway, could be a model for B.C.
Lessons from a tiny Scandinavian country with big oil-and-gas wealth
Hammerfest lives up to its name. Situated on a barren coastal headland 1,300 kilometres north of the capital, Oslo, and just above the Arctic Circle, this Norwegian city of 10,000 gets hammered by winter winds that whip off the Barents Sea. Fifteen years ago the port city was also getting hammered by a sagging fishing sector, in decline since the 1970s, but today Hammerfest bustles with activity and jingles with money—all thanks to the Snohovit LNG plant. Con- struction of the US$5.3-billion plant—a sprawling facility located on Melkoya Island, which was previously inhabited only by nesting seabirds—began in 2003, with the first load of LNG shipped in 2007. Today annual exports of Snohovit LNG sit at around 5.75 billion cubic metres, destined mostly for Spain’s Iberdrola port and the east coast of the United States.
The Norwegian Crown corporation Statoil operates Snohovit and along with another state-owned oil and gas player, Petoro AS, holds a 64 per cent stake in Snohovit, with the rest shared by four other minority investors. At an internal transfer price of $1.74 per cubic metre—the price derived after deducting the costs of bringing the gas from field to market—Snohovit is exporting more than $12 billion of LNG annually (and that doesn’t include exports of the byproducts liquid petroleum gas and condensate, or light oil). So far it is Norway’s, and also Europe’s, only foray into the global LNG market—though the Scandinavian country of some 5.1 million people has been shipping oil and piping natural gas throughout Europe since oil was first discovered on the North Sea continental shelf in the 1960s. Early on, political leaders in Oslo made critical decisions regarding state control, regulation and compensation for development of its oil and gas resources, setting the tone that helped transform a relatively impoverished post-Second World War Norway into one of the world’s richest countries. As British Columbia attempts to enter the LNG market, a town such as Hammerfest—about the same size as Kitimat, another LNG hopeful—offers a glimpse into what is this province’s theoretical future.
On a brisk March day I meet with Morten Bergan, assistant operations manager, at Snohovit. Bergan, an electrician and plumber by trade, moved to Hammerfest for the LNG opportunity from his home in the Lofoten Islands, 400 kilometres to the southwest. After clearing security, we jump into the cab of his late-model Toyota four-wheel-drive pickup truck and enter the half-kilometre-long tunnel that burrows beneath the sea floor and connects the island plant to the mainland. Gulls circle overhead as we emerge on the other side and follow a road that spirals to a high point, where Bergan takes us to view the facility in its entirety.
“This is the biggest money-maker for Statoil. The plant will be in production until 2055 and we’re still finding new sources of gas,” Bergan says over the wind as we stare down at Snohovit’s matrix of pipes and towers, an administration office and four massive tanks capable of storing 250,000 cubic metres of gas, as well as 75,000 and 45,000 cubic metres, respectively, of condensate and liquefied petroleum gas.
Afterward, we hop back in his truck and drive to the operations and administration complex. Bergan leads us to the facility’s nerve centre—a control room that’s like the bridge of the Starship Enterprise. Snohovit is a slick operation that employs 250 people full-time and generates hundreds of other jobs in secondary and ancillary industries in Hammerfest. A half-dozen casually dressed technicians sit at computer terminals, remotely monitoring the flow of gas along sea-floor pipelines from the Snohovit field of three deep-sea gas wells, located 140 kilometres away in the Barents Sea, as well as the German- engineered liquefaction plant, which cools the natural gas and reduces the volume 600-fold. Snohovit capitalizes on the region’s cold arctic air to gain efficiencies and reduce costs for the extremely energy-intensive LNG process.
Morten Bergan, manager at Snohovit LNG, says the plant will be in operation until 2055
Though the Hammerfest plant has had some operational and technical glitches—including problems with the cooling system and a gas leak in December 2014 that could have been catastrophic—it now forms the cornerstone of Norway’s natural gas export sector and the country’s ever-expanding public purse of oil and gas revenues. Norway’s Government Pension Fund Global, the world’s richest sovereign wealth fund founded on oil and gas revenues and launched in 1990, was worth $1.1 trillion as of May 2015, with investments in hundreds of companies worldwide. Foreign companies pay to play in Norway’s oil and gas sector. In the early 1970s, the country enacted laws that gave Statoil ownership of 50 per cent of all oil and gas exploration licences. Furthermore, according to those same laws, Statoil finances 50 per cent of the costs of exploration undertaken by foreign entities (with the proviso that the Norwegian state retains a 50 per cent equity stake) while profits from upstream activities are taxed up to a whopping 78 per cent.
Comparisons between Norway—with its nationalistic stewardship of fossil fuel resources—and Canada’s energy provinces are sobering. Take Alberta first, which, despite producing almost twice as much oil annually as Norway, has socked away just $17.5 billion in its Heritage Savings Fund since 1976—or about 15 per cent of what Norway has put into its sovereign fund since 1990. In B.C., meanwhile—which has been in the natural gas business since the 1980s, when the first wells were drilled in Peace River country—we still don’t have a dedicated fund for growing public wealth from gas revenue and royalties; companies pay a royalty that fluctuates with price. Royalties hit a peak in 2008/09 of $1.3 billion, when gas prices were high, but plummeted to $200 million in 2012/13, even though production volume had tripled since the 2008/09 high. Annual royalties have recovered modestly, but last year’s budget predicts another fall from an expected $542 million in 2014/15 to $344 million for 2015/16.
Now B.C. is scrambling to get into the LNG game with no guarantee that the province will get the hoped-for windfall in return. The province is wooing foreign LNG investors, two of which are state-owned Petro China and Malaysia’s Petronas, at a time when prices in Asia, the target market for future B.C. LNG exports, are soft; meanwhile, the main buyers—China, Japan, Taiwan, Korea and India—are forming a buyer’s club, or block, to keep prices low. According to the Canadian Centre for Policy Alternatives (CCPA), this puts the lie to the business case that arbitrage, or the assumption that B.C. has cheap supplies of natural gas and Asia doesn’t, will underpin a B.C. LNG industry. At a glance, negotiations haven’t gone in B.C.’s favour. Last October Finance Minister Mike de Jong announced an LNG income tax of 3.5 per cent that would rise to five per cent in 2037; that’s notably down from a seven per cent tax that was originally touted in the 2013 budget, along with a proposed prosperity fund that would grow to $100 billion over 30 years. While there was no mention of the prosperity fund last fall, De Jong did offer up another incentive, in the form of a natural gas tax credit, that will enable LNG plant owners to reduce their corporate income tax rate from the current 11 per cent rate to eight per cent, which ministry officials say will help keep B.C.’s industry competitive. On May 20, the B.C. government signed an agreement with Petronas giving certainty to taxes and long-term regulations around LNG. However, the proposed $36-billion project is far from a done deal: it still faces considerable First Nations opposition and environmental concerns over the plant’s potential impact on fish habitat at the mouth of the Skeena River, near Prince Rupert.
The CCPA’s policy analyst Seth Klein argues that by allowing LNG operators to pay just 1.5 per cent in LNG tax, as long as capital investment is being deducted, taxpayers will in essence be on the hook for capital cost overruns. In the case of Australia’s LNG sector, Klein points out, cost overruns have ranged from 15 per cent to 50 per cent, meaning it could be a dozen years or more before operators in B.C. pay the full tax rate. The playing field in contemporary B.C. is much different than it is in Scandinavia’s petro powerhouse. Norway got in the LNG game early, when prices and demand were strong. B.C. lacks a state-owned entity, like Statoil, that can compete on the same terms as international players like Petronas. Nor does B.C., or Alberta, have a history of bargaining hard with oil and gas companies. When Alberta, under then-premier Ed Stelmach, proposed higher royalties in 2010, the province quickly backed down from an increase in the face of industry protest. As for B.C., the finance ministry has reduced the LNG tax and offered corporate tax incentives before the first plant has even been built.
Norway is not immune from the current oil-and-gas price slump, and its citizens are acutely aware of the country’s dependence on oil and gas. However, even before drilling the first exploratory wells in the ’60s, Norway’s leaders established firm control over its oil-and-gas reserves and adopted a take-it-or-leave-it approach to taxation and regulation. Foreign petrol players balked at first but quickly came around, and today Norway’s sovereign fund provides each Norwegian citizen with a nest egg of approximately $200,000.
“We have 6,700 billion Norwegian krone in the government bank account because of oil and gas,” says Morten Bergan as we drive back into the tunnel linking Melkoya Island to Norway’s mainland. “We’re lucky that we had some very visionary politicians back in the 1960s.”