Top Canadian consumers are taking visions of liquefied natural gas (LNG) exports to Asia seriously enough to ask a question: What if terminal proposals for the northern Pacific Coast of British Columbia (BC) jump off industry drawing boards and go into action by landing overseas sales that have so far eluded them all?

The Chemistry Industry Association of Canada (CIAC) and the Industrial Gas Consumers Association of Alberta (IGCA) are urging the National Energy Board (NEB) to inquire into potential cumulative supply and economic effects of the BC lineup.

Rather than continuing to review requests for 20- to 25-year export licenses only one at a time, the NEB should add up all the applications and consider potential overall supply effects, IGCA says.

A list compiled by the industrial consumers points out that the total export volume contemplated by all the LNG terminal projects — 14.4 Bcf/d — implies overseas sales on the scale of all Alberta production at its peak a decade ago.

The CIAC adds that the NEB should also attempt to calculate potential effects on supplies of gas-liquid byproducts if the LNG export terminal lineup makes it into construction and sales.

The consumer group suggests all liquid byproducts should be tracked but special attention should be paid to ethane, which is a key raw material for Canadian petrochemical plants that is embedded in gas and stays in delivery streams unless special extraction is performed.

“We are currently operating our facilities in Canada below capacity because we cannot obtain enough ethane,” the CIAC has told the NEB. “The industry has a feedstock shortage.”

To date, seven Pacific Coast terminal projects and two jumbo pipeline proposals have advanced far enough on paper to enter the Canadian regulatory process. At least another two schemes are in more preliminary planning phases (see Daily GPI, July 9).

BC’s Liberal government won re-election in May on a campaign platform that emphasized provincial political and regulatory support for LNG exports as the key to achieving Alberta-scale development, employment and royalties with known but as yet mostly untapped northern shale gas deposits.

Outside the BC political arena, skepticism prevails, especially about Liberal claims that three terminals will be up and running within seven years, and that resulting production royalties alone will enable the provincial government to build a C$100 billion “prosperity fund” akin to Alaska’s oil savings account (see Daily GPI, May 17). Widespread Canadian industry consensus is echoed in the latest review by Calgary oil and gas shares boutique Peters & Co. A commentary circulated to investors — emphasizing the remote locations and high costs of BC resources, as well as competition and price uncertainty on overseas markets — suggests that the province will do well to have one northern Pacific LNG export terminal built by 2020.

Canadian doubters have plenty of company. Strong reservations about BC’s prospects are expressed in a recent annual report on LNG markets by the International Gas Union (IGU) a Norway-based voice of 120 companies and industry associations that account for nine-tenths of global gas-tanker trade (see Daily GPI, Aug. 26).

“The U.S. will, as it looks now, become a moderate-size exporter,” IGU said. The expectation arises from a proven abundance of low-cost shale gas supplies within reach of established pipelines and coastal sites where terminals can be built for reasonable price tags.

To date, Canada has one advantage on paper. Regulatory approval of licenses for overseas sales has been easier to obtain than in the United States because the NEB has a well-established routine for large-scale exports as a mainstay of Canadian production and pipeline development, IGU said.

But the regulatory advantage is offset by the economics of BC gas prospects. “Costs in Canada far exceed counterpart projects in the United States where the natural gas market is much more liquid,” IGU said. “Moreover, the distance between the proposed [northern Pacific Coast] export facilities and the North American gas pipeline grid is large, and connections are small in both capacity and number.”

On top of high tolls to cover forecast costs near C$5 billion for building new pipelines across BC to the Pacific coast from northern shale deposits, the Canadian industry faces a growing risk: a trend on overseas markets to take advantage of competing North American entries by replacing traditional indexing of LNG’s value to oil, which has kept its Asian prices high, with the U.S. benchmark for gas as a separate commodity, Henry Hub trading.

“Exporting Henry Hub-linked LNG is risky because it forces sellers to produce no matter what happens to Henry Hub, at a production cost largely divorced from the Hub,” IGU said. “This is a problem because Western Canada shale gas will likely be more expensive than the marginal acreage that sets Henry Hub prices. Despite numerous marketing leads for Western Canada’s slate of projects, there are currently no finalized agreements with Asia Pacific buyers.”

But arrangements continue to develop among aspiring exporters of Canadian LNG. The smallest terminal project — BC LNG Export Co-operative part-owned by Haisla Nation, the BC aboriginal community in the proposed export port site at Kitimat — has enlisted new potential participants from the overseas transportation industry. Belgian ship owner Exmar, LNG Partners LLC and LNG BargeCo BVBA announced a letter of intent to build a floating liquefaction operation for BC LNG. The commitment was backed by a C$50 million deposit. Potential participation has also been announced by Bermuda tanker firm Golar LNG Ltd. and Tenaska Marketing Canada.