By Keith Norbury

Canada is almost entirely dependent on one customer, the United States, for its energy exports. Take crude oil, for example. In the second quarter of 2014, 95.7 per cent of Canada’s total crude oil exports went to the U.S., according to statistics from Canada’s National Energy Board. Overall, energy exports accounted for 29 per cent of the value of Canadian domestic merchandise exports in 2013, according to Natural Resources Canada’s 2014-2015 Energy Markets Factbook. In that year, Canada exported $128 billion in energy with 92 per cent, or $118 billion, going to the U.S.

In the other direction, Canada imported $55 billion in energy in 2013. That represented 12 per cent of merchandise imports. But less than half of that imported energy, 48 per cent, was from the U.S.

Canadian oil exports to U.S. still on the rise

Over the years, the U.S. has consumed virtually all the oil Canada exported. And those volumes have risen steadily over the years — from 80.3 million cubic metres in 2000 to 145.9 million cubic metres in 2013. The only dip in those exports came in 2009 during the financial crisis.

For other energy exports, Canada’s reliance on its U.S. customer is even greater. One hundred per cent of Canada’s natural gas exports in 2013 were destined for the U.S., as were all of Canada’s electricity exports. Exports of electricity accounted for 10 per cent of Canadian electrical production. Crude oil exports accounted for 74 per cent of Canadian production in 2013, while natural gas exports accounted for 57 per cent of Canadian production.

In recent years, technological innovations such as horizontal drilling and hydraulic fracturing have enabled U.S. producers to dramatically increase production of both oil and gas, and rely less on imports. According to the U.S. Energy Information Administration, U.S. field production of crude oil reached 8.6 million barrels a day in August 2014. That’s as high it has been since July 1986, and well above the 4 million barrels a day produced in September 2008 at the start of the financial crisis. In fact, in 2014 the U.S. has become the second largest producer of oil in the world, after Saudi Arabia. In 2010 the U.S. became the world’s largest gas producer.

Western Canadian production has also benefited from this revolution, which enables extraction of what is known in the business as “tight oil.” According to Canada’s National Energy Board, light tight oil production in western Canada has grown to 400,000 barrels a day (or 64,000 cubic metres daily) in 2014, which is double the production in early 2011.

Plunging oil prices prompt uncertainty

“The recession would have been a lot deeper in the U.S. and in Canada if it wasn’t for the fact that the energy business was ramping up for new technologies and starting to find new oil and gas, which replaced imports,” said Roger Straathof, who until recently was Vice-President of Energy and Technology banking for Royal Bank of Canada and now serves as a Managing Director of the bank’s National Client Group in Alberta. While those new energy sources have raised fears that the U.S. won’t need Canadian crude any longer, so far those fears haven’t materialized. The U.S. still needs to import about five million barrels of oil a day, Mr. Straathof said.

Nevertheless, he and other energy watchers interviewed for this article agree that Canadian energy exporters cannot afford to rely on the U.S. market. That’s become even more apparent in recent months as oil prices have tumbled, from about $107 a barrel in June for West Texas Intermediate crude, for example, to $77 a barrel at the beginning of November, reflecting increasing global production and lack of demand growth, in view of anemic global economic growth.

Sherry Cooper, Professor at the De Groot School of Business at McMaster University in Hamilton, Ontario, noted that the increase in U.S. production has contributed to declining global oil prices. “It’s interesting that Canada’s exports to the U.S. continue to be relatively strong,” said Ms. Cooper, who was formerly Chief Economist with Bank of Montreal. She warned that in the near future the U.S. will become a net exporter of energy. “So our biggest market is going to become a significant competitor,” Ms. Cooper said. “That’s why it’s more essential than ever that Canada be able to export oil and natural gas to other countries.” And Canada can’t do that without investing in pipelines, she said.

Pipelines’ role in trade diversification

At present, the U.S. doesn’t export oil except for some condensate exports that require special permission, said Paul Frazer, a Washington, D.C.-based special advisor on Canada-U.S. relations to the President of the Canadian Chamber of Commerce. In fact, U.S. law has prohibited oil exports since the Energy Crisis of 1973. However, the U.S. government is considering relaxing those restrictions in the light of increased oil production. In any case, Mr. Frazer noted that pipelines enable “access to markets,” whether they are domestic or abroad. “And that is critical, very critical to the ongoing economic well-being of Canada,” Mr. Frazer said. Dozens of pipelines carry crude oil and natural gas across the Canadian border. However, those pipelines are filling up fast. “Current Canadian crude oil production is nearing maximum pipeline capacity out of western Canada of 3.5 million barrels per day,” noted the 2014-2015 Energy Markets Factbook.

“No matter what business you’re in, it doesn’t have to be oil, it’s always good to have a diverse customer base instead of being dependent on that one country,” Mr. Straathof said. Jean-Sébastien Rioux, whose career includes three years at Imperial Oil, pointed out that “this prolonged agony over Keystone XL just demonstrates that we can be best friends, but still have divergent commercial or environmental or political interests.”

Keystone XL, it hardly needs to be mentioned, is a $7-billion proposed pipeline that TransCanada Corporation plans to build to connect with an existing pipeline system linking the Alberta oil fields to U.S. refineries. President Barrack Obama rejected the initial route for Keystone XL in 2012, and has held off on a decision on a revised route pending the outcome of a court challenge in Nebraska. It is said that, with Republicans controlling Congress after the recent U.S. mid-term elections, Congress could pass legislation approving Keystone XL, which would override a potential veto by President Obama.

Alternatives to Keystone XL

Alternatives to Keystone are proposed pipelines to the Pacific and Atlantic coasts of Canada. They include the Enbridge Northern Gateway pipeline proposed for the port of Kitimat, twinning of the Kinder Morgan pipeline to Vancouver (almost tripling its current capacity), and Trans­Canada’s Energy East pipeline to Saint John, N.B. TransCanada submitted its long-awaited application to the National Energy Board in late October. “There is room for both export via the Keystone XL pipeline to the Gulf Coast but also through the Energy East pipeline,” Trans­Canada CEO Russ Girling said in a conference call.

However, getting any pipeline approved, let alone built, has become an enormous undertaking. They have become lightning rods for protests by environmentalists, First Nations, and farmers who don’t want them traversing their lands. “People don’t trust the energy companies to build something that won’t spill,” Mr. Rioux said. “And if it does spill, they don’t trust them to clean it up and do a good job at it. That’s one thing that has to be overcome.” Depite that, he is confident in the ability of engineers to solve those problems and to demonstrate, in the case of Enbridge, that it can meet the 209 stringent conditions of its environmental permits for Northern Gateway. Then again, “what if a First Nation band just decides to heck with that I’m going to stand in front of the bulldozer?” Mr. Rioux asked. Such a societal crisis, he said, points to the need for a Canadian “consensus on what we should be doing with our natural resources.”

Energy East would be a critical piece of infrastructure

Colleen Mitchell, President of Atlantica Centre for Energy in Saint John, called the Energy East pipeline “a critical piece of infrastructure” that would help Canada get a better price for its landlocked crude. However, she said it’s also important for organizations planning these projects to look at a longer time horizon, of 40 to 50 years, and “don’t have knee jerk reactions to current events.”

In a similar vein, Dr. Warren Mabee, associate professor in the Department of Geography at Queen’s University in Kingston, said Canada, in concentrating on north-south energy infrastructure rather than east-west infrastructure, has probably overestimated the American market.

“We don’t have the infrastructure to get goods across this country outside of a couple of rail lines, a couple of pipes and one wire. That’s kind of it,” Dr. Mabee said. So Canada, particularly in the West, has developed as a supplier to the U.S. Yet as demand as risen in Eastern Canada, that part of the country has increasingly imported from south of the border. “So instead of bringing all of Ontario’s requirements for natural gas across from Alberta or Saskatchewan through the Trans­Canada pipeline, we end up bringing a lot up from the States just because it’s more competitive.”

While pipeline projects stall, rail gets moving

With the existing pipelines at capacity and proposed new ones mired in the regulatory process, additional oil production has been chugging along through another transportation mode. “I think that the big story here is rail,” Mr. Rioux said. Rail exports of oil from Canada spiked in 2013 to 7.4 million cubic metres, valued at $4.1 billion, according to a recent report from the NEB. Yet that volume was still less than the approximately 12 million cubic metres of oil that was exported by ship and just a fraction of the 130 million cubic metres that was exported by pipelines.

Mr. Straathof said rail isn’t the most economical way to transport large volumes of oil “but it will get you to exactly where the oil is worth the most.” And that might not always be to refineries on the U.S. Gulf Coast.

Mark Hallman, Director of Communications and Public Affairs for Canadian National Railway, said in an email that CN moved about 60,000 carloads of crude oil in the first half of 2014. That’s compared with 5,000 carloads of oil across its entire North American network in 2011, the year after CN started testing the transport of crude oils. “CN moved 75,000 carloads of crude oil in 2013, and believes it has the scope to double its 2013 crude oil carload volumes by 2015, to approximately 150,000 carloads,” Mr. Hallman said. About 60 per cent of CN’s crude volumes consist of heavy crude oils from western Canada. The rest is light crude from that region as well as from the U.S. “CN is transporting crude oil mainly to the U.S. Gulf coast region and Canada’s East Coast,” Mr. Hallman said. “CN also moves a small amount of crude to the U.S. East Coast via interchange with other railroads.”

Andy Cummings, Manager of Media Relations for Canadian Pacific, said by email that CP’s crude oil revenues accounted for $375 million in 2013 as it shipped 90,000 carloads of crude oil. Forty-six per cent of that was western Canadian crude. “We anticipate growth to approximately 200,000 carloads in 2015, with Western Canadian crude overtaking Bakken oil as our biggest origin point in late 2014,” Mr. Cummins said. “Our most significant growth in the near term will continue to be in the Gulf Coast and Northeast U.S. markets.”

Has peak rail arrived?

“I don’t know how much further we can go with the rail option,” Dr. Mabee said. “We’re already seeing trouble in Canada where we don’t have enough space on the rails to move the grain around — to the point where the federal government actually had to intervene.” Nevertheless, Dr. Mabee would be in favour of dedicated semi-high-speed railways to move cargo from Alberta to the Gulf Coast or other ports. “It could be a very good alternative for moving oil, primarily because when the day comes that the demand for oil falls off you can still move lots of other things,” Dr. Mabee said. However, such a project, which he called a “a true nation building exercise,” would be beyond the financial capability of a company and would have to be a government initiative.

As the deadly Lac-Megantic disaster that killed more than 50 people in the summer of 2013 demonstrated, moving oil by rail can also be hazardous. Mr. Cummings noted that following the disaster, CP reviewed its safety procedures “including our procedures for securing unattended trains.” “When we must leave trains unattended, crews now face a stricter set of requirements for securing them against movement.” The railway has also imposed a surcharge on shippers using the DOT-111-style tank cars that ruptured in the disaster. That surcharge acts as an incentive for shippers to switch to safer tank cars.

CN took similar measures following the Lac-Megantic crash, Mr. Hallman said. They include a $10 million program for monitoring equipment “to acquire additional monitoring equipment to enhance its strong technological base for early detection of defects and mitigate the severity of accidents.” The railway has also expressed “clear support” for regulatory orders from the Canadian government to phase out or retrofit older DOT-111 cars.

Oil export value dwarfs that of natural gas

According to Industry Canada, crude oil exports to the U.S. totalled $80.7 billion in 2013. That was nearly double the $42.5 billion figure from 2009. In comparison, Canadian exports of natural gas to the U.S. totalled $10.9 billion in 2013. During the past fifteen years, natural gas exports to the U.S. have steadily declined from about 110 billion cubic metres annually to present levels of about 80 billion cubic metres. The value of such exports has also steadily declined, from about $36 billion in 2005 to about $8 billion today.

U.S. gas exports to Canada increasing

Meanwhile, imports of natural gas from the U.S. have been increasing both in volume and value. In 2005, the U.S. exported 9.5 billion cubic metres of gas worth $3.2 billion to Canada. That volume increased to 25.7 billion cubic metres in 2013 and had a value that year of $4.3 billion.

B.C. remains gung-ho on LNG

In its Throne Speech in early October, B.C.’s Liberal government reaffirmed its commitment to developing liquified natural gas (LNG) terminals in the province. Premier Christy Clark is now calling LNG “a chance — not a windfall” that will help B.C. “maintain the same world-class services we rely on,” the Vancouver Sun reported. Later in October, the province revealed its long-awaited tax regime for LNG. It shrinks the government’s take from what had earlier been proposed. B.C. would still skim 1.5 per cent of net revenues during the early stages of production. However, it will now only take 3.5 per cent, compared with seven per cent, from projects once they have recouped their capital investments. Whether that is enough to satisfy LNG producers wasn’t clear as this article went to press. Malayasia-based Petronas, which owns 52 per cent of Prince Rupert’s Pacific Northwest LNG, had threatened to cancel or delay that $11 billion project on Lelu Island if the province didn’t reduce the tax structure.

Mr. Straathof said Petronas has already invested billions of dollars in its B.C. operations including drilling 30 to 40 wells. “So they’re pretty serious about this, but to build all of this will cost many more billions. So I think it’s very important to get some certainty about environmental requirements and also some of the tax requirements.”

The Petronas project is only one of about a dozen LNG proposals for B.C. Most are centred around Kitimat and Prince Rupert, although two proposals are for Vancouver Island. One of those, involving the Huu-ay-aht First Nations, is for an LNG plant near Bamfield on the Island’s west coast.

Ground work has already begun on two LNG projects in Kitimat. For example, Kitimat LNG, a partnership between Chevron Canada and Apache Canada, had about 600 people working on its greenfield site this spring. Since then, however, Apache has bailed out of the project, leaving Chevron to search for another partner. The 10 million tonnes per year project and its associated Pacific Trail Pipeline weren’t shown in a list of final investments decisions for 2015-2016 that the proponents posted in March, according to petrochemical market analytics firm ICIS. The report noted that the developers had not reached terms on long term contracts with Asian buyers.

The biggest project proposed for Kitimat, however, is LNG Canada, a venture involving Shell Canada Ltd., PetroChina, Mitsubishi Corp., and Korea Gas Corporation. Rose Klukas, Kitimat’s Economic Development Officer, called it the most solid LNG project proposed for B.C. It would occupy the site of a former methanol plant. She expected the company will hold off announcing its final investment decision until 2015 after its environmental assessment review is completed.

Working against these projects going ahead any time soon is that the world is now awash with natural gas. Like B.C., Alaska was also banking its economic future on LNG, but has put it on hold because of the global glut in natural gas, the New York Times reported recently.

Canada’s place in the world gas scheme

In 2013, Canada ranked fourth among global natural gas exporting countries, having shipped eight per cent of the world’s 1.05 trillion cubic metres of exports, according to preliminary figures from Natural Resources Canada. Russia is the world’s largest natural gas exporter, accounting for a fifth of global exports.

The U.S. is the world’s largest producer of natural gas, accounting for 20 per cent of global estimated production in 2013 of 3.5 trillion cubic metres. Russia is the world’s second largest producer, accounting for 19 per cent of 2013 global production. Canada was in 5th place, just behind Qatar and Iran.

According to The World Factbook, global reserves of proven natural gas total 187.3 trillion cubic metres. Russia’s proven natural gas reserves are the largest in the world, and amount to 48.7 trillion cubic meters. At 9.5 trillion cubic metres, U.S. reserves are the fifth largest among nations. Canada clocks in at number 20 with reserves of 1.8 trillion cubic meters. It must be kept in mind that these numbers are subject to frequent and substantial revisions, as new discoveries are made, and as technologies are developed to extract previously unrecoverable resources. The bottom line is that at current production rates, Canada and the world have sufficient reserves for at least a century of consumption.

At present, Japan is the world’s biggest importer of natural gas, according to recent report from the Canadian Association of Petroleum Producers (ACPP) entitled An Overview of the World LNG Market And Canada’s Potential for Exports of LNG. “The Asian energy market is significantly closer to the west coast of Canada than are European markets, thus it makes sense for western Canadian producers to examine market opportunities in Asia and those in South East Asia in particular,” the CAPP report said.

B.C. slow to enter LNG race

The race is on to serve those Asian markets with LNG. Natural Resources Canada lists fifteen proposed Canadian LNG projects, all but one in B.C. On a combined basis, the fifteen plants would export four times as much gas as Canada’s current exports. So far, though, Canada has been excruciatingly slow off the mark. Australia and Canada started talking in earnest about LNG development some seven or eight years ago. At the time, Australia already had one LNG plant in operation while Canada had none. Seven years later, Australia has three plants in operation, seven under construction, and six in the planning stages. By contrast, Canada has nil in operation, nil under construction, and three in the planning stages.

Qatar is by far the world’s largest producer of LNG. It had an estimated capacity of 10.78 billion cubic feet a day in 2014, according to a table from Petroleum Economist magazine reprinted in the recent CAPP report. In second place was Australia at an estimated 6.68 Bcf/d in 2014. However, the report projected that Australia’s capacity, which was 2.79 Bcf/d in 2011, would soar to 12.15 Bcf/d by 2016 to zoom past Qatar into first place. And Australia’s capacity is scheduled to keep growing to reach 16.30 Bcf/d in 2018. For Canada, the current hope is that two plants may be in operation by 2020, producing at the rate of 3.78 Bcf/day. Ms. Cooper believes that “Canada could well have missed the boat,” in large measure because she doesn’t think natural gas prices will recover enough to make Canadian gas competitive. “Yes, the world economy is recovering but the growth in energy demand is not. And that’s because people have become far more energy conscious and are economizing, especially in the United States,” Ms. Cooper said.

The U.S. currently has one small LNG liquefaction plant, Kenai Alaska LNG Terminal, which has been in operation since 1969. It was mothballed in 2011, but re-started in 2014. Cheniere Energy Inc plans to start-up its Sabine Pass, Louisiana plant late in 2015. Of eleven LNG receiving terminals in the U.S., operators of nine have requested conversion to export terminals. Two (Cheniere Energy and Freeport McMoran Energy) have received federal approvals to export LNG to any country, and the Petroleum Economist figures that the U.S. will ramp up LNG capacity to 11.38 Bcf/d in 2018, also zipping by Qatar.

Energy in the Maritimes

The four Atlantic provinces also produce and export energy to the U.S. That includes offshore crude oil from Newfoundland and Labrador, refined petroleum products produced by Irving Oil in Saint John, N.B., natural gas from the Sable Island and Deep Panuke rigs off the Nova Scotia coast, and electricity produced in New Brunswick, said Fred Bergman, senior policy analyst with the Atlantic Provinces Economic Council. Mr. Bergman estimated that the Atlantic provinces exported about $16.5 billion in energy products to the U.S. in 2013.

In October 2012, Atlantica Centre for Energy predicted that Sable Island gas would run out within five years. Meanwhile, Deep Panuke, which came online in 2013, is expected to have a life of eight to 13 years. “Both Sable and Deep Panuke gas will not provide enough supply of natural gas to service the Maritime Provinces’ market for more than a decade. According to government estimates, there are additional reserves of recoverable gas in the offshore of Nova Scotia but its exploration and production is suggested by many observers to be too costly relative to U.S. shale gas and that is not expected to change,” said the Atlantica report. Nevertheless, an estimated 80 trillion cubic feet or more of natural gas is in New Brunswick’s Stoney Creek and McCully fields alone, the report noted. That’s enough to supply “existing and future markets for several generations and provide additional justification for the export terminal investment at Canaport LNG,” the report said.

Atlantic provinces also place LNG bets

At present, Canaport LNG, near Saint John, is an import facility for LNG. Its owners, Repsol S.A. of Spain (75 per cent) and Irving Oil (25 per cent) are evaluating the possibility of converting it to an export terminal, using Marcellus Shale from the northeastern U.S. as feedstock.

Three other LNG terminals are proposed for Nova Scotia: Goldboro LNG, a Pieridae Energy (Canada) Ltd. project, to build a terminal in Guysborough county. The company announced in June that it had signed a long-term deal to deliver five million tonnes a year of LNG to western Europe. Bear Head LNG is proposing a $2 billion to $8 billion near Port Hawkesbury. Australia-based Mayflower LNG PTY Ltd. announced in July that it had bought the proposed Bear Head plant for $11 million from a subsidiary of U.S.-based Anadarko Petroleum Corp. Meanwhile, H-Energy, which is owned by India’s Hiranandani Group, plans a $3.3 billion plant and export terminal in Melford, also in Guysborough county. It aims to be in operation by 2020, the Daily Commercial News reported this July.

Atlantica’s Ms. Mitchell said the Canaport proposal is probably closer to the finish line than any of the B.C. LNG proposals. That because it already has infrastructure, including a marine terminal, storage, and pipeline access. “But it doesn’t mean that it will be first to the finish line,” she said.

Spectra Energy’s Maritimes & Northeast Pipeline, which began operation in 2000, runs from Goldboro, Nova Scotia, through New Brunswick, to Dracut, Mass., about 40 km north of Boston. This September, Spectra announced details of a $3 billion proposed expansion of its gas pipeline networks in New England and the Maritimes. The new Access Northeast project, scheduled for service in November 2018, will complement previously announced Spectra ventures including the Atlantic Bridge project, which will include an expansion of the Maritimes & Northeast Pipeline. Eventually, the company plans also to reverse the flow of the existing pipeline, which now brings Nova Scotia gas south into the U.S., to bring Marcellus shale gas to Nova Scotia for export.

The dollar value of natural gas exports from the Atlantic provinces to the U.S., almost all of it to Massachussetts, has already fallen off in recent years from $669 million in 2010 to $257 million in 2013, according to Industry Canada. Meanwhile, the value of natural gas imports from the U.S. to Atlantic Canada has risen from $23 million in 2010 to $205 million in 2013. Ms. Mitchell expressed confidence that the LNG projects proposed for the Maritimes can be economically viable. “August numbers for natural gas at Canaport were just in the $4 range (per million BTUs) whereas in Central and South America, its over $12, and India, China, and Japan, just over $11,” Ms. Mitchell said. “So there’s a pretty good differential there, which would be of interest for exporting.”

Energy future increasingly uncertain

Taking those developments into account is just part of the complex calculus required to predict the future of Canada’s energy trade with the U.S. Not the least of those is how long the shale boom will last. In a recent report titled Drilling Deeper, Canadian geoscientist David Hughes argues that production from shale wells will peak in 2017 and tail off sharply after 2020. Add to that uncertainty caused by the growing opposition to fracking, environmental concerns about fossil fuels and a looming press for a global carbon tax, and court rulings that give First Nations more power to block energy projects, and the future of Canada’s energy trade looks anything but clear. However, even an avowed environmental advocate like Dr. Mabee sees hope for that future trade in such projects as the Energy East pipeline and the LNG terminals. “I’m hugely in favour of these projects not so much because I am committed to seeing every single one of them built, but because they’re allowing us as a nation to finally have this kind of a discussion about what our energy mix looks like and how we might work with each other to benefit us the best,” he said.