The second-biggest Canadian contender to break into the overseas trade in liquefied natural gas (LNG) has picked a site for its entry in the long lineup of proposals to build export terminals on the Pacific Coast of British Columbia.
LNG Canada -- a consortium of Shell Canada and Canadian subsidiaries Petro-China Investment (Hong Kong) Ltd., Korea Gas Corp. and Mitsubishi Corp. -- landed a deal to use a Kitimat wharf and associated land owned by Rio Tinto.
The global mining conglomerate's chief executive, Sam Walsh, called the agreement an example of extracting "meaningful" added value from current assets. Rio Tinto is also spending about US$3.5 billion on modernizing an aging aluminum smelter at the northern Pacific Coast location, with some of the workers housed in bargain-priced quarters aboard an aging, dormant tourist cruise ship anchored nearby.
The LNG terminal site deal was described as a sale of options to lease or buy a share of the port facilities eventually, if and when the consortium lands export sales and makes a decision to proceed into constructing the project. No price, schedule or other details of the arrangement were disclosed, with Rio Tinto calling the terms "commercially confidential."
In a statement confirming the site selection, LNG Canada Vice President Andy Calitz said, "We believe the LNG Canada project represents the best opportunity to bring the liquefied natural gas industry and its benefits to the people and communities of British Columbia."
LNG Canada has also obtained a long-term export license from the National Energy Board (NEB), to load tankers with 33 Tcf of gas over 25 years at a rate of up to 3.2 Bcf/d.
Only the WCC LNG project of Imperial Oil and its 70% owner, ExxonMobil, is larger, with its NEB license to send overseas 39 Tcf in daily ship cargoes of up to 3.9 Bcf.
Like WCC, LNG Canada remains a tentative plan that has yet to firm up dates even for deciding whether to build its project.
The same goes for the entire Canadian lineup to sail into the overseas LNG trade, which has 13 entries that have reached the stage of NEB licensing with proposals for a combined 203 Tcf of exports at a rate of 22 Bcf/d.
Of the projects based on Canadian gas, 10 have selected sites on the Pacific Coast including nine in the northern ports at Kitimat or Prince Rupert and one has located at a discarded southern lumber mill location near Vancouver.
Two schemes before the NEB are plans to fill terminals on the northern Pacific Coast of the United States, in Oregon, with gas siphoned across the border from BC The 13th entry in the lineup has a site on the Nova Scotia coast and has raised a possibility of using shale production to be imported from the northeastern U.S. by reversing flows on the international Maritimes & Northeast Pipeline.
The NEB export licenses include a standard 10-year "sunset clause," giving their holders a decade to land overseas sales, build their terminals and start shipments.
All but the smallest projects call for construction in stages, enabling them to make modest starts on their planned tanker traffic. Almost all are cases of starting from scratch as "greenfield" developments requiring multi-billion-dollar investments including jumbo new pipelines and "upstream" development of Canadian shale gas deposits where drilling remains in "pilot" stages or trials of adapting horizontal drilling and hydraulic fracturing techniques.
A year after BC's pro-development Liberal government made encouraging LNG export development the cornerstone of a successful provincial re-election platform, practical measures to carry out the pledge remain on hold.
The biggest political promise is creation of a provincial "prosperity fund," to fill with C$100 billion (US$90 billion) in saved revenue surpluses to be generated by fulfilling a government target of having at least three LNG export terminals up and running by 2020.
The target has been widely interpreted as a declaration of intentions to impose an export tax -- a phrase that government leaders do not use. BC Finance Minister Mike de Jong said last week that he expects his Feb. 18 budget to outline a revenue collection "framework," but that specifics such as tax rates will likely remain unknown until legislation to enact the scheme is proposed in November.
In the Canadian gas industry capital of Calgary, corporate leaders have repeatedly warned the BC government against jeopardizing LNG terminal project economics and marketing efforts by proposing revenue schemes that rely on over-optimistic gas price forecasts or are liable to scare off potential customers.
The most candid description to date of the LNG lineup's current status remains a statement last fall by the president of Chevron Corp.'s Canadian subsidiary, Jeff Lehrmann, at an industry conference in Calgary.
Chevron acquired a long-range position in Canada's share of North American shale gas resources liable to be available for overseas exports with a 2012 purchases, for an undisclosed price, of a 50% share in the first entry in the BC lineup.
The deal included operating control of KM LNG, which is licensed for 9.4 Tcf of exports at a rate of 1.3 Bcf/d, plus interests in 644,000 acres of northern BC shale gas deposits.
The sellers included Encana Corp., Canada's top natural gas producer, which has said it is switching its priority drilling targets to liquids-rich shale formations chiefly in Alberta and the United States
Development timing for KM LNG depends on how the Canadian project's economics stack up compared to other possibilities in Chevron's global asset portfolio. An Australian LNG development called Gorgon took decades to make the grade, recalled the Chevron executive: KM LNG's turn "may not be today but it might be for the future -- something for my kids or their kids." Shades of the multi-decade faint hope of a big pipe to carry Alaska gas to the Lower 48.