Sable Island national park could permit gas drilling
NO PANACEA
OTTAWA — Proposed government legislation to create a new national park on Atlantic Canada’s famed Sable Island — known for its wild horses and rich biodiversity — will still allow for fossil fuel exploration and drilling deep underground, Environment Minister Peter Kent told a senate committee Thursday.
“No risks have been identified,” Kent said. “Horizontal drilling is a very well established resource tool.”
Kent said that the legislation, introduced in the Senate, was created under unique circumstances since the small island southeast of Halifax “fabled for its wild horses, shipwrecks and one of the largest dune systems in Eastern Canada,” is also in the middle of an active petroleum field. But he praised oil giant Exxon for giving up its surface drilling rights, which would be pro- hibited at the new Sable Island National Park Reserve.
“On their own initiative, they have not had to be cajoled or begged to give up their surface rights,” Kent said. “I believe they told the committee ... that if we were to withdraw this potential future provision for horizontal drilling it would be a deal breaker and we would lose the opportunity to protect Sable Island.”
The Nova Scotia government reached a deal with the federal government in 2011 to create the national park and both pledged to table legislation to restrict oil and gas exploration on the island, in spite of existing corporate drilling rights.
Despite the surface drilling ban, horizontal drilling would allow companies to access deep reserves through an offshore entry point more than one nautical mile away from the island’s boundaries.
Tired of poor refining margins, Imperial Oil Ltd. has been soliciting buyers for its Dartmouth refinery in Nova Scotia since last May, and the announcement of new eastern pipelines has not led to a change of heart at the company — at least for now.
The company has been saying that it has received multiple offers since last October and now expects to make a decision later this year.
“We are still looking at a variety of options that could include selling the refinery or potential conversion to a distribution terminal operation,” said Pius Rolheiser, Imperial Oil spokesman.
Imperial’s stance underscores that while TransCanada Corp.’s Energ y East pipeline and Enbridge’s Line 9 reversal are welcome relief valves for the Canadian energy industry, they may do little to boost the prospects of some refineries in Central and Eastern Canada.
“I would not say it is a panacea,” said Bill Simpkins, an Atlantic Canada representative of the Canadian Fuels Association, an industry body of the country’s refiners including Shell Canada, Suncor Energy Inc. and Imperial.
Eastern Canadian refineries can process synthetic crude oil from Alberta and even some heavy crudes, but only Imperial’s 121,000-barrels-per-day Sarnia, Ont. refinery has a plugged-in coking facility that can process raw bitumen, Mr. Simpkins said.
“No bitumen gets processed outside of Alberta, except if it’s going to the United States. If bitumen ever goes down the TransCanada [eastern] pipeline it will have to be exported somewhere, unless refiners are planning to build a $2-billion coker.”
Irving Oil’s port in Saint John, N.B. offers an export outlet for the bitumen, and the New Brunswick government is pushing to become Canada’s eastern oil hub, but that may take a while.
“It is going to be an evolving market over a 40-year life of the project, and it may start with connections to the eastern and Maritime refineries,” Carl Kirst, analyst at BMO, said. “Ultimately there may be an export line to other countries.”
Suncor’s decision to abandon its $11.6-billion upgrading joint venture in Alberta with France’s Total also puts further pressure on bitumen production and makes the cases for Keystone XL, which would connect to bitumen-processing refineries in the Gulf Coast, and the export-focused Northern Gateway project even more compelling.
Still, the eastern pipelines are a way out for synthetic and other Canadian blends, and have been cheered by refiners seeking alternatives to Brent-priced crude.
TransCanada has asked shippers to confirm interest in its proposal to convert two natural gas pipelines from its east-west Mainline system into oil lines. Once assured of interest, the company will seek a permit from the National Energy Board by the fourth quarter of the year with expected completion date of 2017.
The 850,000-barrel-perday project will take crude from Hardisty in Alberta to delivery points in Montreal, Quebec City, and Saint John, where the Irving Oil refinery is the country’s largest.
RBC Capital Market estimates the pipeline could cost $7-billion, which i ncludes conversion of roughly 3,000 kilometres of existing gas pipe and construction of 1,400 kilometres.
Enbridge plans to reverse its existing Line 9 between Sarnia and Montreal with a maximum capacity of 300,000 bpd.
The new pipelines carrying Canadian oil could support up to 11,000 jobs in Quebec alone over the next 25 years and contribute about $725-million annually to the province’s GDP, according to Joe Oliver, the federal Minister of Natural Resources.
Enbridge estimates its Line 9 reversal will save refineries about $23-billion over 30 years from accessing lower cost crude.
Meanwhile, TransCanada is pitching the pipeline as a cheaper alternative to 600,000 bpd of expensive Canada imports.
Brent-linked OPEC and North Sea crude roughly make up 82% of Eastern Canadian imports, while Mexican and U.S. oil makes up 6%, according to EcoResources Consultants.
While Western Canada Select has seen painful discounts to the U.S. benchmark, these differentials are ex- pected to disappear, if — a big if — Keystone XL is approved.
“Will the differentials last?” Mr. Simpkins asked. “Do refineries base their economics on that and put in a $2-billion coker only to see differentials disappear?”
Eastern refineries are also preoccupied with more compelling cost considerations.
A report by the Canadian Fuels Association claims that at least five of the nine major refineries in Central and Eastern Canada may become economically unviable because of weak margins and overcapacity. “Refining capacity in this region exceeds requirements based on current petroleum product consumption,” the report noted. “The surplus in refining capacity creates downward pressure on refinery profitability.
“This would represent a loss of $3.6-billion a year (including direct, indirect and induced impacts) on Canada’s GDP and a loss of 34,000 jobs.”
Rapid changes in environmental regulations could also hurt the industry as Ottawa brandishes its green credentials, the CFA warned, and the compliance bill could run up to $2.79-billion for eastern refineries alone.
While industry bodies always balk at more regulations, eastern refineries have been through a tough period.
In the past three years, two million bpd of Atlantic Basin refining capacity has shut down, including Shell’s Montreal refinery, while another 500,000 bpd is up for sale.
Suncor says while access to Western Canadian crude will help its Montreal refinery integrate better with its other three refineries, it has no immediate plans to expand or invest in the unit.
Valero, which runs Jean-Gaulin refinery at Lévis, across from Quebec City, says the operation’s profitability is in the “middle of the pack” out of 16 refineries and the company plans to import Texas crude to the unit to reduce costs.
“The world is long refining capacity. Some of the refineries are not going to be as utilized, and you may see some refineries close,” said Bill Day, spokesman at Valero.
“The good news for North American refiners is that they may have a competitive advantage if they can access low-cost crude oil and natural gas.”
Given the brouhaha around pipelines, TransCanada’s east initiative faces the least number of hurdles and seems to have broad political support, including from Quebec.
“We see that [Quebec] government’s evaluation includes factors such as increased profitability for the two refineries in the province, which would lead to greater long-term sustainability of jobs and a higher corporate tax base,” said Robert Kwan, an analyst at RBC in a note.
Construction jobs on the pipeline, refinery expansion and an environmental tradeoff with pipelines displacing oil tankers in the St. Lawrence River may be other factors in Quebec’s final decision.
Meanwhile, New Brunswick is abuzz, especially regarding job creation during the construction phase and the prospect of securing supply for the Irving refinery, says David Campbell, president of Moncton, N.B.-based Jupia Consultants.
“It would likely lead to an export terminal in Saint John,” Mr. Campbell said. “There is some talk of twinning the oil pipe with a natural gas pipe which could provide Canada markets for New Brunswick shale gas at some future date — at least it will connect the region to national pipeline infrastructure.”
There have also been some discussions on the potential of an upgrader in the province, he noted.
“The argument is that Saint John is close to water and doesn’t face Alberta’s high labour costs. But this is more speculative,” he said.