Nuclear power’s loss in Japan is rapidly turning out to spell gain for natural gas — and not least in Western Canada. Aspiring overseas exporters of liquefied natural gas (LNG) heard that encouraging word from international market participants recently in the Canadian industry capital of Calgary.

As the National Energy Board (NEB) opened hearings on applications for 20-year gas export licenses for LNG export terminals planned on British Columbia’s (BC) northern Pacific coast at Kitimat, Noel Tomnay, global gas research chief for consultancy Wood Mackenzie, predicted that “The likelihood is gas will end up being a winner.” Paul Sullivan, global LNG director for engineering firm WorleyParsons, affirmed, “There will be markets for Canada.”

Sullivan told a capacity crowd at a seminar during Gastech’s 2011 Gas & Oil Expo in Calgary, “For Western Canada the simple truth is LNG can transport your gas to a C$10/MMBtu market versus a C$4.50 market.” Two Kitimat export terminal projects effectively have C$5-plus/MMBtu to pay for opening up an LNG channel overseas and make a profit, Sullivan said. “You have to look west to the Pacific markets because that’s where the business is.”

Economic effects are already rippling out to float a rising gas demand and price outlook left by the March wreck of the Fukushima nuclear power station by an earthquake and tsunami, Tomnay said. He reported encountering estimates that the electricity supply loss — 20 gigawatts (GW) at the ruined plant at the northern disaster site, and another 10 GW elsewhere in Japan — will generate LNG demand exceeding 25 million tons per year (about 3.8 Bcf/d). A “very conservative” current forecast by Wood Mackenzie projects annual LNG demand to replace the lost Japanese nuclear power at 10 million tons (1.5 Bcf/d).

The largest Kitimat proposal — KM LNG owned by Apache Canada, EOG Canada and Encana Corp. — by coincidence calls for capacity of 1.4 Bcf/d. The terminal and allied pipelines already hold BC environmental and industrial development approvals, aboriginal support and participation has been secured. The project schedule calls for deliveries to start within about four years from the first of two planned plant stages. Site clearing is under way (see NGI, May 23).

“It’s a nice location for what we want to do,” said Robert Spitzer, exploration vice president of Apache Canada. The port at Kitimat is a stone-walled fjord about 150 feet deep, well sheltered from ocean storms, capable of handling vessels of all sizes and ice-free all year.

Meanwhile, BC LNG Export Co-operative LLC, a joint venture of the Haisla Nation and LNG Partners LLC of Houston (see NGI, March 21), has reported generating a strong response with an initial call for participation in its Kitimat project (see NGI, June 6).

Spitzer said the three partners in KM LNG own about 500,000 acres of mineral rights in northern BC’s Horn River Basin, which he described as richer than the Barnett Shale deposit in Texas. Although both supply sources have comparable areas of 4,400-5,000 square miles, the BC deposit is about twice as thick and estimated to contain up to 200 Bcf per square-mile section.

Recoverable Horn River reserves are currently rated, using the present stage of technical development, at 80 Tcf — double Alberta’s remaining conventional supplies — and Apache alone expects to extract 10 Tcf eventually from 2,000 drilling locations.

Although work has slowed somewhat since the 2008 economic and energy price contraction, Spitzer said pilot programs are continuing with encouraging results as experience is gained with BC versions of horizontal drilling and multiple hydraulic fracturing stages. Expenses are headed down and well productivity is on the way up, he said.

Emerging refinements of the technology include a geosteering method that enables horizontal drilling to follow varying zig-zag angles as well bores are extended, keeping them in the richest parts of the layer cake-like formation, Spitzer said. A three-year-old alliance of 10 companies with drilling rights in the area, the Horn River Producer Group, has secured northern BC community co-operation by developing local employment and training programs and reducing the environmental footprint of roads and forest clearings by using compact pads or bush sites to drill multiple horizontal wells, Spitzer said.

Although Tomnay and Sullivan said pressure has developed for LNG price reductions since the economic contraction and arrival of shale gas, Spitzer indicated that overseas markets remain well inside the range needed by the Canadian export terminal projects. As senior owner and operator of the KM LNG package, Apache is confident it can be done at prices in the range of C$5-5.50/MMBtu, Spitzer said. As the first Canadian entry in both shale production and LNG exports, the KM LNG group occupies the best picks of the mineral rights and construction options, he said.

While KM LNG’s sales targets are Japan, South Korea, China and Taiwan, Tomnay said the ripple effect from the Japanese nuclear power accident is spreading into the more competitive and lower-priced Atlantic region, chiefly Europe. Supplies have shrunk by LNG equivalent to about 2.5 Bcf/d including 1 Bcf/d owed to the Fukushima disaster, 0.5 Bcf/d due to a German decision to cut nuclear power operations, and losses of 1 Bcf/d because of the Libyan civil war, Tomnay estimated.

Wood Mackenzie maintains, “With new nuclear generation likely more expensive — where it can be built — the long-term value of gas has increased.”

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