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Vol. 19, No. 9 Week of March 02, 2014
Providing coverage of Alaska and northern Canada's oil and gas industry

BC gets dose of reality

Finance minister outlines two-tier LNG tax regime; industry says plan first step

Gary Park

For Petroleum News

British Columbia Finance Minister Mike de Jong is taking on the government job of cooling down overheated talk of a cash windfall from LNG exports.

In releasing the province’s 2014-15 budget, which included the first broad strokes of an LNG tax regime, he said the earliest a major LNG facility could be up and running on the British Columbia coast would be 2017 and might take even longer.

Against the bullish sentiments being expressed by Premier Christy Clark — who talks of C$1 trillion in economic benefits over 30 years, a C$100 billion Prosperity Fund to free the province of its debt, which is heading for C$60 billion in the new fiscal year and related jobs of 75,000-100,000 — de Jong cautioned that returns from the LNG sector would be meager in the initial years, if an industry is launched.

He estimated that a single LNG facility producing 12 million metric tons a year would eventually generate C$1 billion in government revenues.

But he pulled that back to more realistic levels, projecting that such a plant would pay only C$50 million a year in taxes during the first four years of operation and not until the sixth year would it generate C$250 million.

“I don’t want to suggest that there’s going to be a cascade of money flowing into a Prosperity Fund in the next five years,” de Jong told reporters.

That is based on the government’s proposal to introduce a two-tier tax rate, starting at 1.5 percent of net income once commercial operations started and as much as 7 percent when project capital costs were recovered.

Budget documents released by the government show the tax would be applied to: The sale of LNG; rents and fees payable for the use of an LNG facility; and fees for processing natural gas at an LNG facility.

Competitive conditions, fair return

“The rates will be finalized in legislation that will ultimately be determined by an on-going analysis of global economic and market conditions, with a view to ensuring British Columbia remains competitive and British Columbians get a fair return from the sale of the natural gas resources they own,” de Jong told the provincial legislature.

The government said the key components of the tax legislation will be introduced this fall, while other legislative components, such as administration and enforcement measures, will be ready for introduction in 2015.

Geoff Morrison, British Columbia manager of the Canadian Association of Petroleum Producers, told reporters that the framework appears workable, although LNG proponents will need time to determine whether the numbers make an LNG investment in British Columbia economically feasible.

“This brings us one step closer to some clarity,” he said. “That’s encouraging, but it’s more complicated than just a tax.”

Morrison said the industry is also waiting for the government to outline other LNG-related policies, including environmental regulation.

2017, ’18 earliest exports

Government officials said the earliest date for LNG exports is likely 2017 or 2018, when BC LNG Cooperative — the smallest of 13 LNG ventures in British Columbia, with Houston-based LNG Partners, the Haisla First Nation and Golar LNG as partners — starts ramping up to exports of 900,000 metric tons a year over 30 years.

De Jong said his projection of C$1 billion a year of government revenues from one project includes corporate and carbon taxes and royalties from natural gas extracted in British Columbia.

“This is how we expect to extract for British Columbians a fair share of the value added, the arbitrage if you will, that results from the conversion and export of our natural gas to other markets in the world,” he said.

Of British Columbia’s lineup of 13 projects, seven hold export permits totaling 82 million metric tons a year from Canada’s National Energy Board and the others are at various stages, ranging from feasibility studies to front-end engineering and design.

No final investment decisions

The major players are Chevron/Apache, Shell, Petronas, BG Group, AltaGas/Idemitsu and Imperial Oil/ExxonMobil, but none has made a final investment decision.

Analysts at Dundee Capital Markets said that although Canada does not hold an edge over its global LNG rivals on “timing, location or a favorable regulatory regime ... the potential benefits could be enormous even if a fraction of the dozen or so projects on the drawing board go ahead.”

They said in a report that the benefits for British Columbia could be similar to the cash windfall for Alberta from the oil sands.

The report said capital spending over the next 20 years, including incremental drilling, gas processing and gathering pipelines, could range from C$88 billion-C$219 billion, with the construction of exporting terminals and sales pipelines adding another C$16 billion-C$43 billion.

But the analysts said they “highly doubted that all projects will get the green light,” noting that more than 25 countries are hoping to enter the LNG liquefaction field.



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More Canadian gas for Oregon LNG

Canada’s National Energy Board sees no reason to deny an export permit of 1.55 billion cubic feet per day of Western Canadian natural gas as feedstock for the Jordan Cove LNG project in Oregon.

It issued the 25-year license to ship the gas out of British Columbia for liquefaction at Coos Bay, Ore., by a limited partnership primarily owned by Calgary-based Veresen.

The NEB said it decided the volume of gas “is surplus to Canadian requirements” because of both the large gas resource base in North America and the ability of the Canadian gas market to “continue to respond appropriately to changes in supply and demand.”

The U.S. Department of Energy has approved Jordan Cove’s plans to export 1.2 bcf per day of LNG to countries which have free trade agreements with the U.S.

However, backers of the $7.5 billion Jordan Cove facility are also in line to seek permission to do business with non-FTA countries.

Oregon LNG has also filed an application with the NEB to export as much as 1.3 bcf of Canadian gas to its liquefaction plant on the Oregon coast.

Oregon LNG has Department of Energy approval to ship 1.25 bcf per day of LNG to FTA countries, but is seeking approval to export an equal amount to non-FTA countries.

Don Althoff, chief executive officer of Veresen, told a Houston conference on Feb. 20 that LNG projects in the works for the U.S. are “adding an interesting wrinkle” to the global LNG pricing structure which is based on crude.

He noted that many of the U.S. projects are being financed and built on U.S. gas price models and most Asian producers will likely use that as leverage to shift the global market.

Althoff said there are already signs of a move in the trading hubs at Singapore and Tokyo, but suggested a wholesale move will only take place over a number of years.

Bill Gwozd, senior vice president of Ziff Energy, told Platts that Asian markets are likely to develop a hybrid pricing strategy as they hunt for lower costs.

He also predicted that most of the current proposed capacity of 30 bcf per day for LNG operations on the British Columbia coast will get built, although the ownership structures and the number of facilities could change.’

Gwozd said Canadian projects will come into service ahead of those proposed in the U.S., because of stronger Canadian economics, although the gas resources of both countries will be needed to meet future global demand.

—Gary Park