The only liquefied natural gas (LNG) import terminal that has been built in the Bay of Fundy is continuing to explore how the facility can remain viable, following the rapid growth in the amount of natural gas being extracted from shale rock in the northeastern U.S.
The Canaport LNG import terminal in Saint John recently received approval from the provincial Department of Environment and Local Government to reload LNG back onto ships, along with a short-term order from the National Energy Board to export LNG. Canaport has not yet set a date for when it might begin exporting LNG, says Canaport LNG media contact Kate Shannon. She explains, "Our terminal has the necessary equipment to load LNG onto LNG tankers. The process will remain the same, but in reverse. We will use existing equipment, and all existing safety processes will remain in place."
She adds, "The approval of this permit allows us to have more flexibility and an additional option to maximize the use of our terminal. LNG would potentially be shipped out to other markets globally. Our terminal is able to meet fluctuating market demand at any given time, and as such, our send-out volumes fluctuate throughout the year."
Barbara Shook, senior reporter-at-large for Energy Intelligence Group in Houston, says that Canaport is looking at exporting LNG "because they have no market at all in the Northeast. Their LNG is so much more expensive than the domestic LNG." She expects that Canaport might export to European markets, noting that the natural gas price in New England is around $4.50 to $4.75 per million btu, while it is over $11 in Great Britain.
LNG imports at Canaport expected to drop dramatically
According to Bentek Energy, an energy market analytics company, Canaport is expected to receive only five deliveries from Qatargas this year. The imports help serve peak winter demand in the New England market through the Maritimes and Northeast Pipeline. However, Canaport has only a three-year contract with Qatargas that expires at the end of this year. Bentek forecasts that LNG imports to Canaport will drop dramatically next year and that the terminal will receive an average of 4.8 billion cubic feet a year under the sole import contract with Royal Dutch Shell. In February, Shell had purchased all of Repsol's LNG assets, except Canaport, which Shell had decided not to purchase because of the decline in LNG imports at the Saint John facility. Repsol and Shell, though, did sign an agreement for Shell to supply one million tons of LNG to the terminal over a 10-year period, which is just over 1% of its capacity, if Canaport was operating at its maximum capacity of 1.2 billion cubic feet a day.
According to the U.S. Energy Information Administration (EIA), during the winter of 2013 the LNG send-out from Canaport was 42% lower than the previous winter. From May 2012 to January 2013, Canaport deliveries to the U.S. averaged 100 million cubic feet per day, which Shook describes as "a minor send-out." Operating at maximum capacity, the Canaport send-out could be 10 times as much. Meanwhile, natural gas production in the northeastern U.S. rose from 2.1 billion cubic feet per day in 2008 to 12.3 Bcf/d in 2013.
Between 2008 and 2013 the natural gas net inflow from eastern Canada to the northeastern U.S. fell by 82%, according to the EIA. Lower production at the Sable Island gas fields and higher demand in eastern Canada contributed to the decrease in natural gas imports. Also, the U.S. began exporting compressed natural gas to Canada by truck from Baileyville.
As for whether Canaport might add liquefaction capacity to convert natural gas to LNG and export from domestic sources, Shook questions whether the Saint John facility would receive approval from the U.S. government to import gas from the U.S. and then export it. She doubts that there would be any natural gas source in Canada, since there is as yet no hydro-fracking of the "trillions of cubic feet" of shale gas in New Brunswick because of concerns about the impact of fracking.
Shook says that Canaport, which began operating in 2009, "was a good idea at the time," which was before the domestic shale gas boom. She notes that nine pipelines from the U.S. run through the Marcellus and Utica shale gas fields, which stretch from Ohio and West Virginia into New York state, and they are all empty. They are being revamped so that their flow patterns will be reversed to go from north to south, since there is a growing natural gas market in the southeastern U.S. for power generation, or they are being converted to handle liquid gas or oil for the southeast.
"We need more pipelines out of the Marcellus field to the Northeast," Shook says, adding, "Gas is a lot cheaper than fuel oil and a whole lot cleaner."
Two pipelines did recently announce that they would be reversing their flows to transport Marcellus shale gas to northern New England and eastern Canada. On December 3, both the Iroquois Gas Transmission System and Portland Natural Gas Transmission System launched open seasons offering capacity on their pipelines to transport gas from the Marcellus field. The Portland pipeline had been built to bring natural gas from Canada into the U.S.