Canadian shale drillers are seeking a liquefied natural gas (LNG) counterpart to a federal corporate tax break that helped kick-start Alberta oilsands development in the 1990s.
The boost is needed to offset cost disadvantages that Asian export terminal projects face on the remote northern Pacific Coast of British Columbia (BC) compared to rival supply sources in Australia, the United States, the Caribbean and the Middle East, says the Canadian Association of Petroleum Producers (CAPP).
The Calgary-based Canadian gas industry expects to learn as early as this spring whether its tax request will be granted, in the forthcoming Conservative government’s annual budget. The administration of Prime Minister Stephen Harper, who represents a Calgary constituency, is renowned for pro-business policy that includes an avowed strategy of building Canada into an “energy super-power.”
CAPP made its case for an LNG tax break during annual parliamentary pre-budget consultations with lobby groups last fall in a presentation to the House of Commons standing committee on finance.
Association President David Collyer — a former executive of Shell Canada, a sponsor of the biggest proposal made so far for LNG tanker voyages from BC — said, “These new market forays face stiff competition from other exporters, particularly Australia.
“Timely development with an efficient regulatory process and a competitive fiscal regime are key to successfully advancing Canada’s interests. The federal government can assist in LNG export infrastructure development by classifying LNG export facilities as manufacturing and processing for tax purposes.”
The reclassification sought by CAPP would enable terminal builders to write off their expenses against corporate taxes at an annual rate of 30%, or almost four times as fast as the 8% pace under rules for the projects in their current designation as resource production sites.
“The current tax classification puts Canadian LNG liquefaction facilities at a significant disadvantage relative to competitors in both the U.S. and Australia,” Collyer told the Commons finance committee.
“It takes about 27 years to write off 90% of an asset” in Canadian LNG “as compared to about 13 years in the U.S. or Australia.” Under the Canadian gas producers’ tax proposal, a 90% write-off would take about seven years, Collyer said. “That…would make Canadian LNG liquefaction facilities much more competitive on an international basis.”
The corporate tax change sought for Canadian LNG installations parallels a concession that the federal government granted for bitumen processing and upgrading facilities at oilsands plants. The tax break for northern Alberta projects, which stopped after development hit stride about seven years ago, was part of a “generic fiscal regime” devised by pro-industry collaboration of the federal and provincial governments.
In the LNG case, BC already granted its provincial counterpart to Alberta’s share in the oilsands incentive scheme. BC charges only a “net profit” royalty for use of deep drilling and new technology to tap gas from designated northern shale deposits where costs are high, including development of new infrastructure.
In the net profit approach, royalty rates are set at a token level until supply development costs including infrastructure construction are paid off. Afterwards, the rates rise on a sliding scale that reflects prices fetched by production, but apply only to revenues after operating expenses. The approach is a departure from Canadian provincial royalties on conventional production, which take cream off the top by collecting a price-adjusted share of gross revenues.
Collyer told the Commons committee that BC tanker terminal projects are “clearly ‘manufacturing and processing’ by creating an LNG product from marketable natural gas. Separation, acid gas removal, dehydration, mercury removal, liquids extraction and distillation towers…all are recognized as manufacturing and processing at straddle plants.”
He was referring to extraction operations along TransCanada Corp.’s Nova gas transmission grid in Alberta, which since the 1970s have taken out ethane as a liquid raw material for petrochemical complexes.
On the left of the BC political spectrum, academic economists and party researchers have branded the break sought by CAPP as a subsidy. Critics’ calculations of potential benefits to export projects run as high as C$2 billion over an eight-year period of terminal development that would be comparable to the lifespan of the federal oilsands tax break.
CAPP and Collyer are not making estimates of the concession’s potential value because it depends on the still unknown number and sizes of LNG export terminal projects that will make it as far as construction.
Target dates for launching tanker voyages out of BC have been repeatedly postponed due to difficulties in landing sales contracts in Asia, where hard-bargaining prospective buyers are taking advantage of the lengthening shale LNG project lineup to break with a tradition of offering high prices linked to oil and demand a switch to a new competitive regime based on indexes driven by low North American gas markets (see NGI, Feb. 11).
Collyer, well aware of industry critics’ penchant for calling favorable tax rates subsidies, insisted that — as in the case of the Alberta oilsands — encouragement for BC LNG will be more than repaid by future royalties, taxes, investment and employment. He estimated that the current, still lengthening lineup of BC LNG projects has potential to build a river of 5 Bcf/d in exports to Asia eventually.
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