What a difference a few years can make. Five years ago, the liquefied natural gas (LNG) debate was raging Downeast, as three proposals for Passamaquoddy Bay were moving forward, along with the Canaport LNG development in Saint John. Now not only is the possibility of the one remaining Passamaquoddy Bay proposal, Downeast LNG in Robbinston, looking increasingly doubtful, but the future of the Canaport facility, which began operating in 2009, is in question because of the large amount of natural gas now being extracted from shale rock. The failure of Canaport to be included in a recent sale package to Royal Dutch Shell is the latest indication of the challenges facing LNG facilities in the U.S. and Canada.
Spanish energy giant Repsol SA, which owns 75% of Canaport, with Irving Oil Corp. owning 25%, had been seeking to sell its LNG assets to help preserve its credit rating and avoid a debt-rating downgrade to junk. Canaport, though, had been a hurdle to closing a deal with Royal Dutch Shell, because of the decline in LNG imports at the Saint John facility. Finally at the end of February, Repsol reached an agreement with Shell for the sale of all its LNG assets, except for the Canaport terminal, for $6.7 billion. The sale reduced Repsol's net debt by more than half. At the time, Repsol reduced the book value of Canaport by $1.3 billion, with the write-down reportedly being the latest case of energy assets in North America falling victim to the shale gas boom.
According to a release from Repsol, Canaport "is not included in the sale process as the low gas prices currently seen in the U.S. market do not allow the asset's medium and long-term potential to be adequately valued." Canaport LNG media contact Kate Shannon adds, "Repsol remains convinced of the asset's strategic importance in the long-term energy needs of North American and will analyze all operational, financial and strategic options available going forward."
Repsol and Shell did sign an agreement for Shell to supply one million tons of LNG to the Canaport terminal over a 10-year period. However, that amount of LNG would supply the terminal for only about 41 days total over the 10 years, or just over 1% of its capacity, if it was operating at its maximum capacity of 1.2 billion cubic feet (bcf) a day. At its current rate of 0.23 bcf/day, the terminal could operate for 212 days total over the 10 years.
Shannon states, "The agreement with Shell is a long-term contract for Canaport LNG to ensure we keep our terminal cold and ready to respond to the demands of the market, with the terminal also being supplemented by other shipments throughout the year, as required by market demand."
However, Barbara Shook, senior reporter-at-large for Energy Intelligence Group in Houston, questions how Canaport can continue to survive. "I don't think there is a future for Canaport as an import facility." She says that the Marcellus and Utica shale gas reserves, which stretch from Ohio and West Virginia into New York state, have so much supply that is no need to import LNG to the northeast. "There is 50 to 100 years of supply, and they haven't defined the full extent of it yet." She adds, "The U.S. doesn't need LNG in the northeast, except in the winter, and they have storage, with the Boston area serving the region adequately."
Shook says the western Canadian producers of shale gas cannot supply eastern Canada, including Quebec and Ontario, as cheaply as U.S. producers can from the Marcellus and Utica fields, so they are looking at exporting LNG from the Canadian west coast to Asia. "The shale gas fields will supply the northeast U.S. and the market in eastern Canada." She notes that the TransCanada Corp. is now proposing to convert part of its mainline from gas to oil and extend the pipeline in order to ship from the Alberta oil sands to refineries in Montreal and Saint John.
If it doesn't sell Canaport, Repsol could convert the facility into an export terminal or storage facility. Shannon says those options could be considered in the future, although there are currently no plans to add an export component to the facility. But Shook says the chances are "slim to none" for Canaport to become an export terminal, because of the shortage of a natural gas supply in northern New England. "You can't get it out of the U.S. or the Maritimes & Northeast Pipeline." Noting that it's a lengthy enough process to receive approval to export U.S. natural gas supplies, she says to export the gas to Canada to then export it overseas at Canaport "would be a major political difficulty."
Dean Girdis, president of Downeast LNG, also doubts that Canaport could be an export facility. "Where would they get the gas? There would need to be a change in infrastructure or new gas in the area." He expects that Canaport will be used to import small volumes of LNG during the winter, when there is a demand. "With small volumes, for 30 days a year it can be profitable."
Shale gas development
Four LNG regasification facilities can provide LNG to New England C Canaport, Distrigas of Massachusetts in Everett, Neptune Deepwater Port and Northeast Gateway, both off Massachusetts. Neither Neptune nor Northeast Gateway has imported any LNG for the past two years. The LNG sendout from Canaport and the Everett facility, near Boston, had been an important source of supply into the constrained New England market during the winter, but between this winter and the previous one those two facilities' sendout as a percent of consumption had declined by more than half. The LNG sendout from Canaport is 42% lower this winter than last winter.
According to the U.S. Energy Information Administration (EIA), imports into the U.S. from Canaport and the Exxon Mobil-led Sable Island project off Nova Scotia through the Maritimes & Northeast Pipeline have declined from 500 million cubic feet a day to approximately 150 million daily. A report from the EIA states that "significant natural gas production increases in the Marcellus Shale region over the past few years have displaced Canadian imports into the northeastern United States."
Along with the shale gas development in the U.S., New Brunswick and Nova Scotia also have been looking at the possibility. In February, the province of New Brunswick released new rules for the oil and gas industry, focusing on protecting water quality and the environment. While the value of the province's gas reserves are not known, the government is implementing a regulatory framework while allowing exploration to continue. Among the issues with the hydro-fracking process that recovers natural gas deposits in shale formations are the volume of toxic waste byproducts and risks to drinking water sources. Shale gas development is being opposed by groups such as the Conservation Council of New Brunswick, which also notes the risk of high levels of greenhouse gas emissions.
Dean Girdis observes that, while New Brunswick has codified the rules for fracking, "it will be three to four years before they even know what they have. It's a very long process to determine what resource exists and then to develop it."
Barbara Shook is more blunt in her assessment. "There is so much shale gas in Atlantic Canada, but they won't allow development," she states. "Let them burn coal then and choke on the particulate matter."
Downeast LNG prospects
Unlike the shale gas debate and Canaport, the smaller Downeast LNG proposal for Robbinston, which would have a capacity of 0.5 bcf/day, has kept a low profile for the past few years. However, the company's application with the Federal Energy Regulatory Commission (FERC) slowly has been proceeding through the licensing process. After a four-year delay, the issuance of a final environmental impact statement (EIS) for the project has been scheduled by FERC. In a March 1 notice, FERC states that the final EIS will be available on July 19, 2013, for a 45-day comment period. The federal agency will be issuing a supplement to the 2009 draft EIS that presents its revised reliability and safety analysis. The deadline for a decision by FERC is set for October 17, 2013.
Girdis says the delay in issuing the final EIS was caused after a review panel determined that the vapor formulation model being used was not properly calculating possible effects. "We're the first project to deal with that issue," he says. "The model didn't exist, and we had to build a model." The Department of Transportation's Pipeline Hazardous Material Safety Administration had to approve the vapor modeling before FERC would issue the final EIS, he notes.
Concerning Downeast LNG's future, Girdis says, "We will finish the permitting and see where we are." He admits that the natural gas market is different now, adding, "Maybe we don't do anything." He says Downeast LNG is not intending to proceed with state permitting, having withdrawn its applications in 2007.
"Anything could happen with the market," he says, noting that if new regulations are developed to restrict fracking, the natural gas market could change. "It will be tough. The price would have to be very high to justify importation" of LNG now, he notes. "The market is not there today, but we don't know what will happen down the road."
Girdis says there are no plans for Downeast LNG's proposal to change to become an export facility. "There would need to be new supply in Nova Scotia or New Brunswick," he says.
Shook believes the Downeast LNG proposal faces the same prospects as Canaport, either as an import or export terminal. "There's no need for it, as long as you have the Marcellus and Utica shale gas fields."
In a filing with FERC concerning the Downeast LNG proposal, Robert Godfrey of Save Passamaquoddy Bay 3-Nation Alliance wrote, "Canaport LNG's falling output during the winter months -- even with room available on the Maritimes & Northeast Pipeline and with Canaport LNG's under-used massive LNG storage capability -- contradicts Downeast LNG's claims for the need for the proposed Downeast LNG import and storage project." He added, "Due to overwhelming evidence of vast, decades-long U.S. domestic natural gas supply, the lack of market for Canaport's LNG, the significantly shrinking imports to Everett LNG, and the two-year absolute absence of imports at Neptune LNG and Northeast Gateway in Massachusetts Bay, all irrefutably point to sufficient domestic natural gas supply without yet another surplus LNG import terminal."