Plans to export liquefied natural gas (LNG) — including the long lineup of terminals proposed for the northern Pacific Coast of British Columbia (BC) — are moving too slowly to cut the North American supply glut for at least three years, according to the National Energy Board (NEB).
An annual gas review by the NEB includes a reality check on political enthusiasm for LNG export schemes, hydraulic fracturing of northern shale deposits and visions of vast government gas royalties that BC’s Liberal party rode to re-election on provincial voting day last Tuesday.
Although the NEB has contributed to the high hopes by swiftly granting 20- to 25-year export licenses to all three LNG terminal projects that have applied for them to date (see Daily GPI, April 12), the federal agency also upholds its long tradition of erring on the sober side in conservative energy supply and demand forecasts.
The board remains unconvinced by years of talk among Canadian financial and industry analysts about the imminent emergence of truly international gas markets, akin to the global oil trade. Instead, the NEB rates the LNG outlook as much like the condition of the North American gas market, as in a “holding pattern” while sorting out price, supply and demand effects of shale development in the United States (see Daily GPI, May 13).
The board’s new forecast acknowledges that the effects include emerging gas-on-gas sales competition in Asia as rival Canadian, U.S. and Australian export projects erode formerly close links between LNG and oil prices.
“Due to lengthy project development timelines, significant LNG exports from North America are unlikely over the 2013–2015 period of this analysis. With North American natural gas prices below those in other parts of the world, North America is also unlikely to attract significant additional LNG imports,” said the NEB.
“Some natural gas drilling in Western Canada is likely being postponed since Canadian LNG projects are taking longer than anticipated to obtain sales commitments from gas purchasers. A key issue appears to be resolving pricing terms. Buyers appear to be seeking contracts with prices indexed to lower-priced North American natural gas. Sellers appear to be seeking the more traditional indexing to higher priced crude oil” (see Daily GPI, April 18; April 3).
Pioneering pilot projects continue in northern BC and Alberta shale deposits known as Horn River and Montney. But the activity remains more a case of field trials of horizontal drilling and hydraulic fracturing under Canadian conditions than supply development.
The exception is hot action in sweet spots where shale gas is rich in oil-like vapor that condenses into premium-priced petroleum liquids. But drilling campaigns for tight oil and allied liquids have a side effect of prolonging Canada’s contribution to the North American gas surplus.
The side effect results from provincial resource conservation regulation that was born in Alberta 75 years ago and has been adopted by the country’s other two main supply jurisdictions, BC and Saskatchewan. Companies that want oil and allied liquid hydrocarbons also have to take gas that comes with them. Flaring off gas is tightly restricted by increasingly strict regulation, which is nowadays driven by environmental concern as well as the original motive of resource husbandry (see Daily GPI, May 13).
The NEB said, “Canadian and U.S. producers who switched away from developing dry gas to earn higher returns by developing oil and natural gas liquids (NGL)-rich prospects appear to be producing enough natural gas as a byproduct to extend this period of abundant North American gas deliverability. Growth in NGL supply has reduced NGL prices and is eroding some of the incentive behind drilling for wet gas.”
The gas glut is headed for a further boost as a result of a U.S. project sponsored by a Canadian export pipeline out to keep its system as full as possible. The NEB points to construction this year of a spur inlet to Alliance Pipeline where it crosses North Dakota on its route to Chicago from northern BC and Alberta, a 79-mile stretch of 12-inch diameter pipe for gas coming out of the Bakken oilfield (see Daily GPI, Oct. 11, 2012).
“Significant gas production associated with the development of crude oil in the Bakken Formation in North Dakota did not have access to a pipeline and had to be flared in the field,” NEB said. “With the construction of a pipeline in 2013, it [the Bakken byproduct] will serve as an additional source of U.S. natural gas supply and another potential competitor for Canadian natural gas being delivered into the U.S. Midwest.”
Rather than try to predict even the near future of Canadian supplies on the unsettled North American market, the NEB projects scenarios driven by prices. If a market recovery occurs into the area of US$6.00/MMBtu by 2015, the NEB expects gas drilling to revive to a point where Canadian deliverability averages 13.2 Bcf/d in 2015, down only 6% from 14 Bcf/d in 2012.
A moderate recovery to US$4.35/MMBtu would enable a modest Canadian supply response, propping up deliverability to an average 12.5 Bcf/d as of 2015. But if prices stagnate at about US$3.70/MMBtu, the NEB expects Canadian gas deliverability to slip to 11.4 Bcf/d by 2015, down 18% from the 2012 average of 14 Bcf/d.
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