A steady stream of more than 450 oil tankers calls at ports in Eastern and Atlantic Canada every year, drawing little public attention.

That’s in part due to the industry’s safety record in the region, where accidents involving tankers are rare. 

The most recent serious pollution incident from an oil tanker took place in Nova Scotia more than 45 years ago, and the last recorded minor spill from a tanker occurred 25 years ago, following a grounding incident in Labrador.

“Marine shipping as a whole is extraordinarily safe when you look at nautical miles travelled versus incidents,” said Meghan Mathieson, director of strategy and engagement for Clear Seas, an independent not-for-profit that studies marine shipping issues. 

“In Canada, shipping is much safer than your morning commute driving in a vehicle. Of the spills that do occur, most come from fuel from pleasure boats or fishing vessels,” she said. 

“People should not conflate debates about the pros and cons of fossil fuel production with marine safety. Is it safe to ship oil and gas in Canada? Yes, it is.”

Where tanker traffic occurs

Prior to the 2024 completion of the Trans Mountain expansion, about 85 per cent of oil tanker traffic in Canadian waters took place in Atlantic Canada, according to Clear Seas.

The increase in tanker traffic off the B.C. coast has shifted the overall balance to 58 per cent of movements on the West Coast and 42 per cent on the East Coast.

Map courtesy Clear Seas

In Atlantic Canada, this is divided between Saint John, NB, which sees about 115 tankers annually importing crude oil, and the Whiffen Head facility in Newfoundland, where 90 tankers are loaded for export every year.

There are also an estimated 240 shuttle tanker transits annually along the St. Lawrence Seaway in Quebec, moving oil between a storage facility in Montreal and a refining facility in Lévis.

Mathieson says there is greater familiarity with oil tankers in Atlantic Canada than in other areas. 

“They have been used to seeing tankers carry oil for a lot longer in that region. But there’s a cultural component as well. Wherever you are in Atlantic Canada, you are not that far from the ocean,” she said. 

“A lot more people work in the marine sector, such as fishing and offshore oil, than other parts of the country, or they know people who do. They are on the water more, so they may be more familiar with the advancements made by the industry to make it safer.”

How tanker safety has evolved

Many of those improvements came in the wake of the 1989 Exxon Valdez oil spill in Alaska’s Prince William Sound. 

Graph courtesy International Tanker Owners Pollution Federation

“Catastrophic incidents tend to stay in people’s minds when discussing marine safety, but so much has changed in the industry in terms of standards and procedures since then,” Mathieson said. 

“Today’s tankers are designed to be safer—they have double hulls and reinforced attachment points for towing equipment. And the procedures and protocols have advanced just as much, from having local pilots guide them into port to inspections by Transport Canada and certified response organizations for spill clean-up.” 

Spill response organizations on both coasts

Eastern Canada Response Corporation (ECRC) is responsible for responding to spills throughout Atlantic Canada as well as the Great Lakes, Quebec, and St. Lawrence Seaway. 

ECRC is the eastern counterpart to the Western Canada Marine Response Corporation (WCMRC), which is responsible for protecting all 27,000 kilometres of Canada’s western coastline. 

In anticipation of increased tanker traffic from the Trans Mountain expansion, WCMRC completed Canada’s largest-ever expansion of marine oil spill response capacity, doubling its capabilities with new vessels and response bases.

ECMRC’s area of response runs from the Alberta/B.C. border to offshore Newfoundland and from the U.S. border to the 60th parallel.  

Part of the marine community

“We have six response centres located throughout the area that face different challenges based on climate and other factors,” said Michael Kean, manager for the ECRC’s Dartmouth Response Centre, which covers parts of New Brunswick, Prince Edward Island and Nova Scotia as well as the Northumberland Strait and Cabot Strait shipping areas. 

“Some of those areas will ice over for parts of the year, as an example, while our region remains ice free. But regardless of the different challenges, we are training around the year so we are ready.”

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Four years ago, Craig Timmermans’ two Ontario radio stations became Canada’s first to go on the air from off the grid.  

Faced with an $80,000 connection fee and ongoing electricity delivery costs, Timmermans opted for another solution: solar and propane.  

“I did our power calculation: five staff, hot water tank, heating system, etc., right down to a coffee maker…then we need a heating source, so it made sense to go with propane,” he said. 

“When I looked at all the different heating systems, I found that propane is hands down the most efficient.”  

Now Timmermans is building a new home that will run exclusively on propane. He says he wanted propane appliances due to their efficiency. 

“A propane cooking stove is the best cooking appliance…The heat is continuous, it’s instant. It just works so well.” 

Lower environmental footprint 

Propane serves many purposes in Canada, from supporting mining and oil and gas operations to fueling heating, cooling, cooking and power in remote, off-grid communities. 

In these communities, propane can replace diesel with a lower environmental footprint. Propane’s carbon intensity is estimated at 72 grams of CO2 equivalent per megajoule, compared to 100 grams for diesel.  

That could be slashed by more than half with a move to renewable propane, according to the Canadian Propane Association (CPA). The CPA has commissioned a new report that looks at potential pathways to producing renewable propane in Canada.  

Pairing with heat pumps and hybrid energy systems 

The report serves as the foundation of the CPA’s roadmap for scaling up renewable propane production in Canada.  

The CPA says the fuel is ideal for pairing with electric heat pumps to provide back-up heat in low temperatures, especially in remote regions that are not near natural gas grids.  

It’s also promising for hybrid systems where solar or wind provides baseload energy and renewable propane provides support when renewables are not available. 

Part of propane’s appeal – renewable or otherwise – is that it’s easily liquefied and stored in pressurized cylinders, making it a versatile energy source used almost anywhere, the CPA says. 

“We want to make sure we reduce emissions while keeping in mind affordability and reliability as key pillars in any energy transformation,” said CEO Shannon Watt. 

“Propane goes where other fuels can’t go.” 

Producing renewable propane 

Today, most propane produced in Canada comes as a byproduct from natural gas processing.  

Among other sources, renewable propane can be co-produced with renewable diesel and sustainable aviation fuel, made primarily from plant and vegetable oils, animal fats or used cooking oil. 

Cost is the barrier to renewable propane production – about double what it takes to produce conventional propane, the CPA says.  

The United States is offering incentives for renewable propane that are not available in Canada.  

Through the Inflation Reduction Act, Renewable Fuel Standard and Low Carbon Fuel Standard, renewable propane producers can receive C$20 per gigajoule (or more than C$30 per GJ in California).  

Through Canada’s Clean Fuel Regulations, the incentive is just over C$5 per GJ, or about C$10 per GJ in British Columbia.  

“In order to attract investment the same way as the U.S. under the Inflation Reduction Act, we need to have competing measures in place,” Watt said.  

“We’ve got the technology and we’ve got the feedstocks. We’ve got a lot of those big puzzle pieces that we need. Now we need the dollars to flow.” 

Exporting renewable propane to the world 

A large-scale renewable propane industry wouldn’t just benefit Canadians, she said.  

That’s because global demand for propane is growing.  

Market research firm IMARC Group projects world propane use will rise to nearly 250 million tonnes by 2032, more than one-third higher than demand last year.  

The transition to cleaner energy sources is a major factor propelling growth, analysts said. 

Until recently, Canada’s only propane exports went to the United States. That changed with the startup of two export terminals at Prince Rupert, B.C.  

Since 2017, Canada’s propane exports outside the U.S. have grown substantially, reaching 42 per cent of total propane exports in 2023, according to the Canada Energy Regulator. 

“We export more and more propane to non-U.S. locations,” Watt said.  

“Now, roughly 50 per cent of Canadian propane is shipped to South Korea, Japan and Mexico, displacing higher emission intensity sources, namely coal and timber.” 

Exporting renewable propane would take the benefits a step further, she said.  

“That carries the conversation on about reducing global emissions and not just what’s happening in our own backyard.” 

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Introduction

The Russian invasion of Ukraine is having an impact on the world’s natural gas markets. Natural gas supply security has become a key concern for governments and industries worldwide.

According to the International Energy Agency (IEA), natural gas is among the world’s fastest-growing energy sources, representing more than 23 per cent of global energy demand ( IEA, 2022). Natural gas is vital to the energy mix in many emerging economies, including countries in the Asia-Pacific region.

Recent forecasts from various sources predict a growing demand for natural gas in the short-term as developing countries move away from coal. In the last few years (2019-2023), the demand for and production of natural gas has fluctuated across regions. World demand for natural gas has increased by two per cent in that time, while world production has increased by just one per cent. Demand for natural gas in the Asia-Pacific region increased by 11 per cent while production in the region increased by only 7 per cent.

As the world’s fifth-largest producer of natural gas, Canada has the potential to capitalize on energy demand in the Asia-Pacific region.

In this CEC Research Brief, we explore North American natural gas price differentials, as well as prices for natural gas in significant Asian trading hubs, including Japan, South Korea, and the average in the region.

Source: Author’s calculations from IEA (2022)

Current Reliance on the United States and Prospects in Asia

In Canada, 98 per cent of natural gas production takes place in Alberta and British Columbia. Alberta’s gas production represented 63 per cent of total Canadian natural gas production in 2020.

All of the natural gas Canada exports is sent to the United States, though such exports have been decreasing in recent years. The emergence of shale gas in Western Canada and the United States has changed international natural gas market dynamics, increasing supply and decreasing prices.¹

In 2021, about 99 per cent of the total natural gas imported by the United States came from Canada, with nearly all transported to the U.S. by pipelines. In 2021, Canada exported 2.78 trillion cubic feet (tcf) to the U.S., down from its peak of 3.78 tcf in 2002. However, the expansion of shale gas production in Canada and the U.S. has also created an opportunity for both countries to supply new markets in Asia.

1. Beyond shale gas being lower cost, many other factors influence natural gas prices including demand and supply, production and exploration, storage and withdrawal, weather, and access to demand markets, such as the Asia-Pacific region.

Source: EIA (2023)

Natural Gas Price Differences Between Canada and the U.S.

Between 1990 and 2021, US Henry Hub and Canadian AECO-C natural gas spot trading prices closely tracked each other. However, short-term price differences can be significant and advantageous to the U.S. (see Figure 3).²

• For example, the prices were closest to each other in 2008 when U.S. natural gas sold for US$8.85 per million British thermal units (mmbtu), just 11 per cent higher than the US$7.99 per mmbtu that Canadian (AECO-C) natural gas fetched that year.
• In contrast, the price gap was widest in 2018 when U.S. natural gas sold for US$3.13 per mmbtu, 179 per cent higher than the US$1.12 per mmbtu average price for AECO-C natural gas that year.
• Between 2019 and 2021, the price gap between US Henry Hub and AECO-C natural gas fluctuated from a high of 98 per cent in 2019 to a low of 26 per cent in 2020. In 2021, U.S. natural gas sold for US$3.84 per mmbtu, 40 per cent higher than the US$2.75 per mmbtu average price for AECO-C natural gas that year.

According to Alberta’s Energy Regulator (AER), many factors cause the observed price differences between AECO-C and Henry Hub natural gas, infrastructure constraints being among the most significant. Other factors include demand and supply, the exchange rate, and transportation costs. The AER estimates that the AECO-C and Henry Hub price differential will increase to US$0.98 per mmbtu by 2031 (AER, undated)

2. According to the EIA, most of the spot price volatility in Canada’s AECO-C trading hub is due to regulatory changes for Western Canada’s pipeline operations.

 Sources: BP Statistical Review of World Energy (2022)

Natural Gas Prices in Asia and Comparisons with Henry Hub and AECO-C

In contrast to the relatively close tracking between U.S. and Canadian natural gas prices over time, the opposite is true when comparing the Canadian with the Asian average price over the years, and in country-specific comparisons with Japan and South Korea.

Natural gas prices skyrocketed worldwide in the last two years, and Asia was no exception. In 2021, the Asian natural gas price was US$18.60 per mmbtu, compared to US$4.40 mmbtu in 2020, an increase of 323 per cent (see Figure 4).

Historically, natural gas prices in Asia on average have been much higher than in Canada. The exceptions were in 2003, when Asian spot prices were just three per cent higher, and in 2005, when they were three per cent lower than in Canada. In most other years, the percentages and prices for natural gas sold in Asia have been significantly higher than in Canada.

For example,

• In 2021, natural gas sold for US$2.80 per mmbtu on the AECO-C trading hub and for US$18.60 per mmbtu in Asia; US$15.88 per mmbtu more, or 564 per cent higher.
• The trend since 2009 has been for Asian natural gas prices to be higher than Canadian natural gas prices by triple percentages, i.e., selling for between 122 and 775 per cent more in Asia than in Canada, depending on the year.

Sources: BP Statistical Review of World Energy (2022) and International Monetary Fund (2023)

Price comparisons between Canada and Japan generally follow the same pattern; since 2009, price differences between Canada and Japan have been substantial (see Figure 5).

• Price divergence between Japan and Canada began to increase in 2006. Every year after 2006, prices for natural gas in Japan were higher, from 22 per cent more (in 2006) to 751 per cent more (in 2018).
• In 2021, the dollar gap between prices in Canada and Japan was US$7.27 per mmbtu; natural gas sold for US$2.80 per mmbtu in Canada and US$10.07 mmbtu in Japan that year, or 260 per cent more.

Sources: BP Statistical Review of World Energy (2022)

In a comparison with South Korea, where data is available only from 2009 onward, prices for natural gas in that country have always been above those in Canada with the difference ranging from US$1.90 per mmbtu in 2009 to US$15.80 per mmbtu in 2021.

Sources: BP Statistical Review of World Energy (2022)

Natural Gas Pricing in Recent Years

Many factors influence global natural gas prices, including supply and demand, production and exploration levels, the location and size of storage facilities, weather patterns, and buyers’ and sellers’ views of future trends.

In the last two years, two factors have had a profound impact on gas prices. First, Russia’s invasion of Ukraine disrupted global gas supplies and resulted in skyrocketing global gas prices. Second, as the world economy opened up after the COVID lockdown, the demand for natural gas in both developed and developing countries increased.

Benchmark oil prices, such as Brent crude or West Texas Intermediate (WTI), are available for global markets. However, there are no comparable significant international benchmark prices for natural gas. Spot prices for natural gas are region-centric. For example, Henry Hub is the benchmark price for North American natural gas. In Alberta, it is AECO-C; in the U.K., it is the National Balancing Point (NBP); in the Netherlands, it is the Title Transfer Facility (TTF); and in the Asian-Pacific LNG market, it is the Japan/Korea Marker (JKM).

The AECO-C is the spot trading price for Alberta gas. The AECO-C hub is Canada’s largest natural gas trading hub, and the AECO-C price serves as a benchmark for Alberta wholesale natural gas transactions.

The AECO-C natural gas price is discounted compared to the benchmark price for natural gas in North America, the Henry Hub price. Henry Hub is the central pricing point for natural gas produced in the United States. The AECO-C and Henry Hub price differential increased in 2022 to more than US$2.00 per mmbtu (see Figure 7).

Source: Derived from the Rystad Energy UCube (2023)

The discount for Canadian natural gas relative to Henry Hub exists partly because Alberta and other western Canadian natural gas fields are further away from U.S. markets than American suppliers, and Canadian transportation costs are thus higher.

This, combined with the fact that the U.S. is currently the only market for Canada’s natural gas (Canada has yet to complete a single LNG export terminal, though one is under construction at Kitimat, British Columbia) means that AECO-C natural gas has traded at a discount of more than US$2.00 per mmbtu in recent years, or about 60 per cent of the Henry Hub price.

However, lower natural gas prices in Western Canada can benefit from upcoming liquefied natural gas (LNG) projects designed to transport natural gas to Asia-Pacific markets because they will reduce an LNG plants’ input costs.

As noted earlier, in recent years, a new benchmark has been developed for LNG in Asia-Pacific markets—the Platts Japan/Korea Marker (JKM)—which is now the benchmark price for LNG deliveries in Japan and Korea. Japan and Korea are among the largest global importers of LNG accounting for 41 per cent of the world’s LNG imports (see Figure 8).

Canada is a late entrant into the LNG market. At one point, 18 LNG projects were proposed. One, LNG Canada, is under construction in B.C. Four additional facilities are proposed in the province: Woodfibre LNG, Tilbury LNG, Cedar LNG and Ksi Lisims LNG.

Given that the demand for LNG in the Asia-Pacific market is currently being filled by traditional players such as Qatar and Australia, the entry of new players, such as Canada, will create a different dynamic in the coming years. The AECO-C benchmark natural gas price is lower than the Asia-Pacific benchmark LNG price, which could mean that buyers in the Asian-Pacific might turn to Canadian LNG for supply, assuming the near- to medium-term completion of LNG projects in Canada.

Source: BP Statistical Review of World Energy (2022)

Canada’s Natural Gas Advantage

Western Canada currently has a cost advantage over other LNG-exporting countries such as the U.S. and Australia.

• This is partly due to lower ambient temperatures in Canada’s western provinces (cooler temperatures help lower liquefaction costs). Specifically, British Columbia’s temperature is cooler than other major LNG-producing regions such as Qatar, Australia, and the U.S. Gulf Coast. British Columbia has an energy efficiency advantage of 34 per cent over Australia, 32 per cent over Qatar, and 26 per cent over the U.S. Gulf Coast for LNG liquefication.
• Qatari LNG is the most competitive from a cost perspective. However, LNG buyers have concerns about becoming overly dependent on one country. Shipping costs to Northeast Asia from Canada are estimated at about 96 cents per mmbtu. In comparison, shipping costs to Northeast Asia from the U.S. Gulf of Mexico are estimated at US$2.22 per mmbtu (see Figure 9). Further, Canada’s West Coast is closer to Japan than Qatar is to Japan; Qatar is 11,773 kilometres from the Japanese port of Himeji and 12,056 kilometres away from the port at Sodegaura. Meanwhile, Canada’s westernmost port (Kitimat) in British Columbia is 7,698 kilometres from Himeji and 7,322 kilometres from Sodegaura.

Source: Wood Mackenzie (2022)

• Canadian LNG going to Northeast Asia is also among the lowest emitting sources of LNG. Canadian LNG has fewer upstream and liquefaction emissions than the average Northeast Asia LNG supplier (see Figure 10).

These distinct advantages of Canadian LNG offer a compelling case for Canadian liquefied natural gas exports to the Asia-Pacific.

Source: Wood Mackenzie (2022)

Conclusion

Comparing the market for natural gas in the form of LNG between Western Canada and the Asia-Pacific shows that the price difference between Canada and Asia provides an opportunity for natural gas produced in Canada to be exported to Asia Pacific markets.

The Russian invasion of Ukraine and the after-effects of the COVID pandemic have rekindled the debate about global energy policies. The world is looking for energy security and every country wants to reduce its dependence on one country for the majority of its energy needs.

The lower liquefaction and shipping costs coupled with the lower cost of the natural gas itself in Western Canada translate into lower LNG prices in Canada. Those advantages will help make Canadian LNG very competitive and attractive to the Asia Pacific market.

The price differentials, along with Canada’s natural advantages, give Western Canada an excellent opportunity to supply natural gas to the Asia-Pacific markets at competitive prices while also bolstering energy security for countries such as Japan and Korea. Canadian LNG could be a strong competitor to the traditional natural gas exporting countries now serving the Asia-Pacific LNG market.

References (All links live as of February 25, 2023)

Alberta Energy Regulator (Undated), Natural Gas Prices, <https://www.aer.ca/providing-information/data-and-reports/statistical-reports/st98/prices-and-capital-expenditure/natural-gas-prices>.

BP (2023), Energy Outlook, 2023 edition, <https://www.bp.com/en/global/corporate/energy-economics/energy-outlook.html>.

BP (2022), Statistical Review of World Energy 2022 (71st edition), <https://www.bp.com/en/global/corporate/energy-economics/statistical-review-of-world-energy.html>.

Canadian Energy Regulator (2017), Market Snapshot: LNG Projects have an Energy Efficiency Advantage Compared to Other LNG Producers in Warmer Locations, Government of Canada, <https://www.cer-rec.gc.ca/en/data-analysis/energy-markets/market-snapshots/2017/market-snapshot-lng-projects-have-energy-efficiency-advantage-compared-other-lng-producers-in-warmer-locations.html>.

Claudio Steuer (2019), Outlook for Competitive LNG Supply, Oxford Institute of Energy Studies, <https://www.oxfordenergy.org/publications/outlook-competitive-lng-supply/>.

International Energy Agency (IEA) (2022), World Energy Outlook 2022 <https://www.iea.org/reports/world-energy-outlook-2022>.

IEA (2022), Gas Market Report Q4-2022, <https://www.iea.org/reports/gas-market-report-q4-2022>

International Monetary Fund (IMF) (2023), Global price of LNG, Asia (PNGASJPUSDM), Retrieved from FRED, Federal Reserve Bank of St. Louis, <https://fred.stlouisfed.org/series/PNGASJPUSDM>.

J. Peter Findlay (2019), Canadian LNG Competitiveness, Oxford Institute of Energy Studies, <https://www.oxfordenergy.org/wpcms/wp-content/uploads/2019/12/Canadian-LNG-Competitiveness-NG-156.pdf>.

Natural Resource Canada (Undated), Energy Facts, Government of Canada, <https://natural-resources.canada.ca/science-and-data/data-and-analysis/energy-data-and-analysis/energy-facts/20061>.

Rystad Energy UCube (2023), Upstream Solution, <https://www.rystadenergy.com/services/upstream-solution>.

U.S. Energy Information Administration (Undated), Natural Gas Imports and Exports, Natural Gas Explained <https://www.eia.gov/energyexplained/natural-gas/imports-and-exports.php>.

Wood Mackenzie (November 2022), The Role of Canadian LNG in Asia, Public Report (November), <https://www.canadianenergycentre.ca/wp-content/uploads/2022/11/WM-CEC-Role-of-Canadian-LNG-in-Asia-Public-Report.pdf>

CEC Research Briefs

Canadian Energy Centre (CEC) Research Briefs are contextual explanations of data as they relate to Canadian energy. They are statistical analyses released periodically to provide context on energy issues for investors, policymakers, and the public. The source of profiled data depends on the specific issue.

About the authors

This CEC Research Brief was compiled by Ven Venkatachalam, Chief Research Analyst, Canadian Energy Centre and Lennie Kaplan, Executive Director of Research, Canadian Energy Centre. The authors and the Canadian Energy Centre would like to thank and acknowledge the assistance of two anonymous reviewers in reviewing the data and research for the initial edition of this Research Brief.

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Research and data from the Canadian Energy Centre (CEC) is available for public usage under creative commons copyright terms with attribution to the CEC. Attribution and specific restrictions on usage including non-commercial use only and no changes to material should follow guidelines enunciated by Creative Commons here: Attribution-NonCommercial-NoDerivs CC BY-NC-ND.

Terra Nova, an oil production, storage, and offloading vessel majority-owned by Suncor Energy, has returned to Newfoundland and Labrador waters after a $500 million overhaul.

The work is expected to extend production at the Terra Nova oil field by 10 years, delivering economic benefits to the region and an additional 70 million barrels to global markets.

“Oil production is a big part of our GDP,” says Danny Breen, mayor of St. John’s, N.L.

“During the time oil production from Terra Nova wasn’t there, our GDP was very low. It’s expected next year we’re going to lead the country in GDP growth and that’s due to the return of oil production.”

The Terra Nova project is a significant employer and business spender. In the third quarter of 2022 alone – without any oil production – it directly employed 713 people and spent $8.9 million with businesses in N.L. and Canada, Suncor reports.

The benefits of Terra Nova run much deeper than on-site employment, says Charlene Johnson, CEO of Energy NL, an energy advocacy group.

“Consider the thousands of people in the service and supply sector when you look at the benefits in terms of taxes and royalties to the province,” she says.

Projects off the coast of N.L. have produced more than one billion barrels of oil since the Hibernia platform started operating in 1997.

“Our capabilities in the offshore are second to absolutely no one,” says Johnson.

The Terra Nova vessel can store 960,000 barrels of oil and accommodate a crew of 120. Stationed 350 kilometers offshore near producing wells on the Grand Banks, it offloads crude oil onto large shuttle tankers for shipment.

The 292-metre, double-hulled vessel hasn’t operated since 2019. Suncor says production will resume by mid-2023.

Suncor Energy’s Terra Nova FPSO. Photo courtesy Suncor Energy

In the meantime, Breen sees promise in the industry’s future.

“If you look at overall oil production, there are so many resources left,” he says. “It will be a big part of our economy in the years to come. It will continue to produce revenue for the province.”

While the main market for Newfoundland and Labrador’s offshore oil is the United States, projects sent an average of about 83,000 barrels per day to Europe between 2015 and 2021, according to Statistics Canada.

Those oil exports had a total value of $11.4 billion.

Europe’s top five purchasers of Canadian offshore oil over the last half-decade were the United Kingdom ($4.1 billion), Italy ($2.3 billion), Netherlands ($2 billion), Spain ($1.8 billion), and Ireland ($457,000).

While Europe’s energy supply from renewable sources like wind and solar is growing, oil and gas will remain critical to the energy mix for decades to come, according to BP’s latest world energy outlook. Oil and natural gas are expected to still supply nearly 30% of Europe’s energy demand in 2050.

There are four producing oil fields off the coast of Newfoundland and Labrador: Hibernia, Hebron, White Rose and Terra Nova, when it resumes.

The Terra Nova income stream will help Newfoundland and Labrador diversify its energy mix and transition to a technology-based green economy involving hydrogen production and critical metals, says Breen, noting the project helps prevent emigration from the province.

“If that production is not happening, then people will have to look for work elsewhere,” he says.

There are an estimated 80 million barrels of oil left in the Terra Nova oil field, says Suncor.

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Trans Mountain Corporation continues to work on the largest-ever expansion of spill response on B.C.’s south coast.  

The company, which is twinning the Trans Mountain pipeline from Edmonton, Alta. to Burnaby, B.C., has delivered 40 of 44 spill response boats as part of a $150-million investment in Western Canada Marine Response Corporation (WCMRC). The WCMRC fleet includes custom-built spill response boats, deck and tank barges, landing craft, skiffs and workboats. 

Trans Mountain, in its fall Marine Progress Report, also announced that WCMRC has hired 119 of 123 new full-time positions. The company said significant progress has been made on constructing six new bases that can handle potential ship-source marine spills. 

The enhancements, said Trans Mountain, will double WCMRC’s existing response capacity and significantly reduce response time.  

The Trans Mountain project has loaded petroleum on marine vessels off the south coast of B.C. with no spill incidents in nearly 65 years of tanker operations. 

“The Trans Mountain project, right from the beginning, started thinking about the impacts on the marine environment – it did a lot of listening,” said Robert Lewis-Manning, president of the Chamber of Shipping, a leading Canadian marine transportation industry association.  

“It reached out to a lot of networks of people, including those in industry, those in local communities, and those in First Nations along the route of the shipping channel.” 

WCMRC is the only Transport Canada-certified marine response organization on Canada’s west coast. Its mandate, said Trans Mountain, ensures there is a state of preparedness in place when a marine spill occurs and to mitigate coastal impacts, including wildlife protection public safety. 

Pursuant to conditions set out by the Canada Energy Regulator and the B.C. Environmental Assessment Office, Trans Mountain has also filed its Plan for Marine Spill Prevention and Response Commitments. Other milestones in progress include submission of a Marine Mammal Protection Program and an Indigenous Marine Outreach Program. 

“That effort to build those capabilities wasn’t something that Trans Mountain Expansion project was required to do by regulation but chose to go above and beyond the regulatory requirement that the project was bound to implement,” said Lewis-Manning.  

“This project is going to have a few lasting legacies, but I think the most important one will be the relationships and networks that have been developed.” 

WCMRC is an industry-funded organization with more than 2,300 members. Membership is mandatory for vessels of a certain size calling on Canadian ports, as well as for oil-handling facilities receiving or shipping oil across their docks. 

The Trans Mountain Pipeline is owned by the Government of Canada through Trans Mountain Corporation, a subsidiary of the federal Crown corporation Canada Development Investment Corporation. The pipeline twinning adds 980 km of pipe and increases capacity from 300,000 barrels per day to 890,000. 

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The Trans Mountain project has reached another milestone in its work to strengthen marine safety off the coast of B.C., in partnership with a local First Nation community.   

Oil tankers have been loading from the project’s Westridge Marine Terminal without a single marine spill in more than 65 years of operations.  

Now the high-powered tugboats that escort tankers and help navigate in the unlikely event of a failure will soon provide this service along a much larger stretch of the shipping lanes that link the Westridge Marine Terminal with open water. 

“Our number one job is to keep the coastline safe,” says Sean Leet, CEO of Horizon Maritime, which will provide the new tug services as part of KOTUG Canada Inc.  

“The Sc’ianew First Nation have partnered with us on the proposal from the start and that was our vision for these assets that had the primary responsibility of keeping the coastline safe to be in Sc’ianew territory.”  

The new tugs will operate out of a new docking station at Beecher Bay in the Cheanuh Marina, which is owned by the Sc’ianew First Nation. The location near Sooke, B.C. is about 150 kilometers southwest of the Westridge terminal. It’s approximately where right now, tug escorts with Trans Mountain tankers end. When the project is complete, tugs will accompany tankers past Beecher Bay and out to open water.  

The 9,000 horsepower tugboats are each 50 metres long and capable of providing about 120 tonnes of pulling power.  

Sc’ianew members will be trained to work on board tug crews when they go into operation, KOTUG says.  

“What our new expanded tug escort arrangement will do is ensure there is a tug travelling with the latest tanker all the way out to the Pacific Ocean,” says Trans Mountain master mariner Bikramjit Kanjilal. 

“It expands a safety element that is already present and now covers for the entire time that the latest tanker is traveling in Canadian waters. If something takes place that’s outside the control of the [tanker] or the control of the pilot and requires outside assistance, then that assistance is already traveling with the vessel. It’s right there.”   

New technology built on the tugs such as efficient engines and special graphene paint are expected to reduce underwater noise and improve energy efficiency, KOTUG says.  

The new docking station at the Cheanuh Marina will also be home to a new large ocean-going oil spill response vessel owned by KOTUG, in a separate contract with the Western Canada Marine Response Corporation (WCMRC).  

It’s part of Trans Mountain’s $150-million investment in WCMRC on the largest-ever expansion of spill response on B.C.’s south coast, part of the conditions on the expansion project mandated by the Canada Energy Regulator.  

WCMRC is building six new spill response bases, including two 24/7 on-water bases, as well as doubling the size of its response vessel fleet from 44 to 88, and adding 137 full-time positions, primarily for spill response personnel.  

As of fall 2021, 34 of the additional vessels have been delivered and eight are being built, while 110 of the new full-time positions have been filled, Trans Mountain has reported.  

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Overview

Despite Canada’s position as one of the world’s top oil producers with one of the largest global oil reserves, crude oil imports into Canada have become a significant part of the country’s energy mix, particularly since 2000.

This Fact Sheet uses Statistics Canada’s International Merchandise Trade Database to track the flow of imports of crude oil (i.e., petroleum oils and oils obtained from bituminous minerals) into Canada between 1988 and 2020. We then analyze the source of those imports by country, break down the oil imports by province, and then break down the 2010 to 2020 figures. We also compare the value of crude oil imports with other imports to provide a sense of the relative value of Canada’s oil imports.¹

In short:

• Between 1988 and 2020, Canada spent $488 billion nominal ($604 billion in 2020 dollars) on foreign oil imports;
• Quebec is by far the largest importer of foreign oil into Canada, importing $228 billion worth of foreign oil since 1988;
• Between 2010 and 2020, Canada’s oil imports from just the United States and Saudi Arabia totaled over $110 billion;
• Using census data from 2016, along with our own calculations, we determined that the value of foreign oil imports that year amounted to $1,021 per household based on a national average (including Quebec); and
• When the value of Quebec’s foreign oil imports in 2016 is matched to the number of households in Quebec that year, foreign oil imports to Quebec were worth $1,576 per household annually in 2016.

1. There are a number of factors that explain Canada’s level of foreign crude oil imports, including the type of oil a refinery is designed to process and ongoing pipeline constraints. In this Fact Sheet, we do not offer “pro” or “con” policy prescriptions; just hard data which the public and policymakers can use as a base for discussion. Note that we make clear in other reports that Canada is a net beneficiary of the international oil trade and for that and other reasons—the benefits of free trade writ large—the data herein should not be interpreted as a call to restricted trade in oil, but rather, an end to artificial, activist, and political barriers and for Canada’s crude oil to be extracted and shipped cross-country to be used domestically and internationally.

Canada has imported nearly 9 billion barrels of foreign oil since 1988

Between 1988 and 2020, Canada imported nearly nine billion barrels of crude oil from other countries, an average of over 745,000 barrels per day over the period. Crude oil imports into Canada more than doubled between 1988 and 2008, increasing from 148 million barrels to nearly 329 million barrels annually. Since 2008, crude oil imports to Canada have fallen by about 37 per cent, yet at over 206 million barrels in 2020, they remain nearly 39 per cent above the 1988 level.

The value of foreign oil imports from 1988 to 2020: $488 billion nominal or $604 billion in 2020 dollars

The value of crude oil imports into Canada grew gradually between 1988 and 1999, from $2.8 billion to $6.9 billion in those years. Foreign crude oil imports then nearly doubled to $13.7 billion in 2000 and continued to grow steadily to nearly $34 billion by 2008 (see figure 1). There was a sharp decline to $21 billion worth of imports in 2009, coinciding with the Great Recession, but growth resumed and crude oil imports reached $29.8 billion in 2012. Despite lower crude prices beginning in 2014, the value of annual foreign crude oil imports into Canada remained at over $14 billion through to 2019 when imports reached $18.9 billion before falling to $11.5 billion in 2020 due to COVID-19.

In total, between 1988 and 2020, Canada spent $488 billion importing crude oil from such countries as Saudi Arabia, Iraq, Russia, Azerbaijan, Nigeria, Algeria, Angola, Venezuela, and Kazakhstan, as well as the United Kingdom, Norway and, more recently, the United States.

• On an inflation-adjusted basis, Canada spent $604 billion importing foreign crude oil between 1988 and 2020.
• On an inflation-adjusted basis, Canada spent $5.5 billion on foreign oil imports in 1988 ($2.8 billion in nominal dollars) compared with the $18.9 billion it spent on such imports in 2020.

Source: Derived from Statistics Canada, Canadian International Merchandise Trade Database.

Foreign oil imports by province from 1988 to 2020: Quebec highest at $228 billion

Between 1988 and 2020, Canada’s foreign crude oil imports in nominal dollars ranged from nil in Prince Edward Island and $200 million in British Columbia to $228 billion in Quebec where import values were the highest (see Figure 2a).

Central and Eastern Canada are generally more reliant on foreign oil imports than Western Canada, in part due to the lack of critical pipeline infrastructure from Western Canada. Insufficient pipeline capacity continues to be a problem despite the 2015 reversal/expansion of Enbridge’s Line 9B pipeline, which has enabled Ontario and Quebec refineries to source more oil from Western Canada. Historically, New Brunswick’s Irving Oil Refinery also relies on foreign oil imports.

Source: Derived from Statistics Canada, Canadian International Merchandise Trade Database.

Value of foreign oil imports per household

Combining census data from 2016 on the number of households with the value of foreign oil imports that year allows for a per-household comparison (see figure 2b).

• In 2016, the value of foreign oil imports to all of Canada was just under $14.4 billion. Quebec’s portion of such imports was nearly $5.6 billion. There were nearly 14.1 million households in Canada that year, with over 3.5 million of them in Quebec;
• The value of foreign oil imports amounted to $1,021 per household based on a national average (including Quebec); and
• When the value of Quebec’s foreign oil imports in 2016is matched to the number of Quebec households, the value of foreign oil imports to Quebec was $1,576 per household.

Sources: Derived from Statistics Canada, Canadian International Merchandise Trade Database and the 2016 Census

Foreign crude oil imports by country from 1988 to 2020

Canada has imported crude oil from a number of countries over the past three decades (see figure 3). Between 1988 and 2020, the five largest exporters of foreign crude oil to Canada were the United States ($94.6 billion), followed by Norway ($79.0 billion), the United Kingdom ($62.6 billion), Algeria ($58.4 billion), and Saudi Arabia ($44.4 billion).

Source: Derived from Statistics Canada, Canadian International Merchandise Trade Database

Canada’s historic oil suppliers: The United Kingdom, Norway, and Nigeria

• The United Kingdom was once a consistent source of foreign crude oil for Canada; imports from it reached an annual value of $5.2 billion in 2008 before falling off in the current decade as its oil production declined; as of 2020, the value of U.K. oil imports to Canada was just $63 million.
• Norway was also once a significant source of foreign crude oil for Canada; the value of imports from it reached over $5.6 billion in 2008, but fell off with the Great Recession of 2009 and the crude oil price decline that started in 2014. In 2020, the value of oil imported to Canada from Norway was just $345 million.
• Nigeria has been another major source of foreign crude oil for Canada; the value of imports from that country peaked at $2.4 billion in 2011, but fell off to just $611 million in 2020.
• Venezuela was also a source of foreign crude oil for Canada between 2000 and 2007 at a value of nearly $11.8 billion, but as of 2008, Canada imported no oil from Venezuela;
• Algeria emerged as a key source of foreign crude oil for Canada between 2000 and 2013; the value of imports from it peaked at nearly $6 billion in 2012 before falling to zero between 2016 and 2020; and
• Other nations such as Azerbaijan, Angola, and Kazakhstan have also been sources of crude oil for Canada, primarily between 2008 and 2014.

Since 2005, Saudi Arabia has increasingly become a key source of foreign crude oil for Canada. And after 2007 when its shale oil production began to soar, the United States also increased its role as a significant supplier of crude oil to Canada.

From 2010 to 2020 Canada relied more heavily on the United States and Saudi Arabia

Canada’s mix of suppliers of foreign crude oil has become less diverse over time, particularly in the last decade.

• Between 2010 and 2020, Canada’s oil imports were worth a total of $231.1 billion. U.S. oil imports accounted for nearly $84.2 billion, followed by imports from Saudi Arabia at $26.3 billion. That is over $110 billion in foreign oil imported to Canada from those two countries alone in that decade (see Figure 4).

Derived from Statistics Canada, Canadian International Merchandise Trade Database.

Imports of crude oil compared with imports from other key sectors, 2010 to 2020

Canada spent nearly $238 billion on crude oil imports between 2010 and 2020 (see Figure 5). This is:

• Higher than the almost $192 billion Canada spent on farm, fishing, and intermediate food products imports;
• Higher than the nearly $205 billion Canada spent on aircraft and other transportation equipment and parts imports; and
• Just below the $256 billion Canada spent on forestry products and building and packaging materials imports.

Source: Derived from Statistics Canada, Canadian International Merchandise Trade Database

Comparing imports of oil from Saudi Arabia worth over $26 billion with other imports

Between 2010 and 2020, Canada spent over $26.3 billion on crude oil imported from Saudi Arabia (see Figure 6). This $26.3 billion expenditure is larger than the:

• $1.7 billion Canada spent importing coffee from Brazil;
• $2.5 billion Canada spent importing coffee from Colombia;
• $7.8 billion Canada spent importing fruits, nuts, citrus fruits, and melons from Mexico;
• $9.2 billion Canada spent importing edible vegetables and certain roots and tubers from Mexico;
• $16.4 billion Canada spent importing footwear from China; and
• $19.9 billion Canada spent importing pharmaceutical products from Germany

Source: Derived from Statistics Canada, Canadian International Merchandise Trade Database

A 2020 snapshot: 89% of all the oil imported to Canada comes from the U.S. and Saudi Arabia

In 2020, the U.S. was Canada’s largest source of foreign crude oil at a value of nearly $8.8 billion, followed by Saudi Arabia at a value of $1.5 billion (see Figure 7). Together, these two countries were the sources of about 89 per cent of all the oil imported by Canada, or nearly $10.3 billion of the $11.5 billion total value of that oil in 2020. Other countries were very distant thirds as sources for crude, such as Nigeria (at a value of $611 million), Norway ($345 million), and the United Kingdom ($63 million).

Source: Derived from Statistics Canada, Canadian International Merchandise Trade Database

Conclusion

Imports of crude oil to Canada have been rising over the past two decades and the value remains high ($11.5 billion in 2020) despite the decline in crude oil prices beginning in 2014 and continuing with the onslaught of COVID-19 in 2020.

While Canada is among the world leaders in both crude oil reserves and crude oil production, it spent $488 billion between 1988 and 2020 to bring in crude oil from such countries as Saudi Arabia, Russia, Azerbaijan, Nigeria, Algeria, Angola, Venezuela, and Kazakhstan, along with United Kingdom, Norway and, more recently, the United States.

Quebec has been the largest importer of foreign oil between 1988 and 2020 (45 per cent of the total imported to Canada), at a value of $228 billion.

The value of foreign oil imports per household, using 2016 census data, was $1,021 per household (nationally, including Quebec) and $1,576 per household annually specific to Quebec.

Notes

This CEC Fact Sheet was compiled by Lennie Kaplan and Mark Milke at the Canadian Energy Centre (www.canadianenergycentre.ca). The authors and the Canadian Energy Centre would like to thank and acknowledge the assistance of Philip Cross in reviewing the original data and research for this Fact Sheet. Photo credits: Lewis Pratt from Unsplash.com

References (All links live as of July 8, 2021)

Statistics Canada (undated), Canadian International Merchandise Trade Database <https://bit.ly/37XDr7y>; Statistics Canada (undated), Table 12-10-0133-01: Canadian international merchandise trade by province and country, and by product sections, customs-based, annual <https://bit.ly/3g12J8g>; Statistics Canada (2017), Families, Households and Marital Status Highlight Tables, 2016 Census <https://bit.ly/2YppR9B>; U.S. Energy Information Administration (2020), International: Petroleum and Other Liquids <https://bit.ly/2QeWang>.

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Introduction

Natural gas is one of the world’s fastest-growing energy sources, representing more than 23 per cent of global energy demand, according to the International Energy Agency (IEA). Natural gas is vital to the energy mix in many emerging economies, including countries in the Asia-Pacific region.

Recent forecasts from a variety of sources predict a growing demand for natural gas in the coming decades. The IEA forecasts that despite the dip in demand for natural gas in 2020, 2021 will be a year of gradual recovery and natural gas requirements will rebound during the year. The IEA also believes that in 2021 the Asia-Pacific region will account for half the global growth in natural gas consumption.

As the world’s fourth-largest producer of natural gas, Canada has the potential to capitalize on energy demand in the Asia Pacific region. In Canada, 71 per cent of marketable¹ natural gas is produced in Alberta, followed by British Columbia with 27 per cent, Saskatchewan with 2 per cent, and only minor amounts produced in Eastern Canada (as of 2019).

Dependence on America and opportunities in Asia

All of Canada’s natural gas exports go to the United States though such exports have been decreasing in recent years. (The discovery of shale gas in Western Canada and in the United States changed international natural gas market dynamics, increasing supply and decreasing prices.²) In 2018, Canada exported 7.8 billion cubic feet per day to the US, but in 2019 just 7.4 billion cubic feet per day.

However, the expansion of shale gas production in Canada and the US has also created an opportunity for both countries to seek new markets in Asia. In this CEC Sheet, we explore the differential between prices for Canada’s natural gas and prices for natural gas in significant trading hubs worldwide, including Germany, Japan, South Korea, and the Asian average. Relative to Western Canada and the Asia Pacific market for natural gas (in the form of Liquified Natural Gas, or LNG), the price difference between Canada and Asia provides an opportunity for Canadian natural gas producers to export to Asia Pacific markets.

Natural gas price differences between Canada and selected markets

Closer US-Canada prices

Between 1990 and 2019, US Henry Hub and Canadian AECO-C natural gas spot trading prices have closely tracked each other, though the price differences could still be significant and to the advantage of the US (see Figure 1).³

• For example, the tightest price gap was in 2008 when US natural gas sold for U$8.85 per million BTU, just 11 per cent higher than the US$7.99 that Canadian (Alberta’s AECO-C) natural gas fetched that year.
• In contrast, the largest percentage gap was in 2018 when US natural gas sold for U$3.13 per million BTU, 179 per cent higher than the US$1.12 average price for Canadian (Albertan) natural gas that year.

1. Marketable natural gas consists of at least 90 per cent methane and meets the specification for pipeline transport and sale for general distribution to the public.
2. Beyond lower-cost shale, many other factors influence natural gas prices, including demand and supply, production and exploration, storage and withdrawal, weather, and access to demand markets, such as the Asia-Pacific region.
3. From October 2019 through March 2020, there was little difference in the spot prices between the AECO-C trading hub in Canada and Henry Hub in the US. In April and May 2020, AECO-C natural gas spot prices increased compared to Henry Hub. According to the EIA, most of the spot price volatility in Canada’s AECO-C trading hub is due to regulatory changes for Western Canada’s pipeline operations.

Source: BP Statistical Review (2020).

Three comparisons on natural gas prices from Asia

In contrast to the (somewhat) close tracking between US and Canadian natural gas prices, the opposite is true in comparisons between Canada and the Asia average price over the years, and in country-specific comparisons with Japan and South Korea.

In most years since 2000, average natural gas prices in Asia have been higher than in Canada (see Figure 2). The exceptions were in 2003 when Asian spot prices were three per cent higher and in 2005 when they were three per cent lower than in Canada. In most other years, the percentages and prices for natural gas sold in Asia have been significantly higher than in Canada. For example,

• In 2012, natural gas sold for US$2.27 per million BTU in Canada on the AECO-C trading hub, but for US$18.15 in Asia, or $15.88 more, fully 699 per cent higher.
• 2018 saw the largest percentage gap with natural gas selling for US$1.12 per million BTU in Canada but US$9.80 in Asia, or $8.68 more (775 per cent higher).
• The trend since 2009 has been for Asian natural gas prices to be higher than Canadian natural gas by triple percentages, i.e., selling for between 122 and 775 per cent more in Asia than in Canada depending on the year.

Sources: BP Statistical Review (2020) and International Monetary Fund (2021).

Price comparisons between Canada and Japan and South Korea mostly follow this same pattern; since 2009, price differences between Canada and both countries has been substantial (see Figures 3a and 3b).

• Prices in Japan were lower than in Canada only in 2003 and 2005 (by 1 per cent and 17 per cent).
• In every other year, prices for natural gas in Japan were higher by from 3 per cent (in 2004) to 797 per cent (in 2018).
• The highest dollar gap between prices in Canada and Japan was in 2012 when natural gas sold for US$2.27 per million BTU in Canada but US$16.75 in Japan, $14.48 higher, or 638 per cent more.
• In South Korea, where data are available only from 2009 onward, prices for natural gas have always been above those in Canada, with a range of between US$1.90 and US$13.63 more per million BTU (in 2009 and 2013 respectively).
• Measured as a percentage, natural gas prices in South Korea have ranged from 56 per cent more in 2009 to 771 per cent higher in 2018. That year, natural gas prices were US$9.94 per million BTU in South Korea and just US$1.27 in Canada, $8.84 higher in South Korea.

Source: BP Statistical Review (2020).

Source: BP Statistical Review (2020).

Canada’s natural gas advantages

Of note, Western Canada currently has a cost advantage over other LNG exporting countries such as Qatar and Australia.

• That is due in part to lower ambient temperatures in Canada’s western provinces (cooler temperatures help lower liquefaction costs). Specifically, British Columbia’s temperature is cooler than that of other major LNG producing regions such as Qatar, Australia, and the US Gulf Coast. (British Columbia has an energy efficiency advantage of 34 per cent over Australia, 32 per cent over Qatar, and 26 per cent over the US Gulf Coast for LNG liquefication.)

• Shipping costs to Japan from Canada are estimated at between 99 cents and $1.09 per million BTU. Shipping costs to Japan from Qatar are estimated at between $1.50 and $1.54 per million BTU. Shipping costs to Japan from US Gulf of Mexico are estimated at between $2.40 and $2.45 per million BTU.

• Also, Canada’s west coast is closer to Japan than is Qatar, which is 11,773 kilometres away from the Japanese port of Himeji and 12,056 kilometers away from the port at Sodegaura. Canada’s westernmost port (Kitimat) in British Columbia is 7,698 kilometres away from Himeji and 7,322 kilometers away from Sodegaura. These distinct Canadian advantages offer a compelling case for Canadian LNG exports to the Asia Pacific.

Summary

The above data on the liquefaction process and shipping costs, coupled with the lower cost of the natural gas itself in Western Canada, translate into relatively lower LNG prices in Canada, and help make Canadian LNG significantly more competitive and thus attractive to the Asia Pacific market. The natural gas price differentials and Canada’s natural advantages give Western Canada a good opportunity to supply natural gas to the Asia-Pacific markets at competitive prices. Canadian LNG could be a strong competitor to the traditional natural gas exporting countries now serving the Asia-Pacific LNG market.

Natural gas pricing: A primer

Many factors influence global natural gas prices, including supply and demand, production and exploration levels, the location and size of storage facilities, weather patterns, and buyers’ and sellers’ views of future trends.

Benchmark oil prices, such as Brent crude or West Texas Intermediate (WTI) are available for global markets. However, there are no comparable significant international benchmark prices for natural gas.

Spot prices for natural gas are region-centric. For example, Henry Hub is the benchmark price for North American natural gas. In Alberta, it  is NOVA/AECO-C; in the UK, it is the National Balancing Point (NBP); in the Netherlands, the Title Transfer Facility (TTF); and in Asian-Pacific LNG market, the Japan/Korea Marker (JKM). Other regions in Canada with their own spot prices include Station 2, Alliance ATP, and Dawn in Ontario.

The AECO-C is the spot trading price for Alberta gas. The Alberta AECO-C hub is Canada’s largest natural gas trading hub, and the AECO-C price serves as a benchmark for Alberta wholesale natural gas transactions.

The AECO-C natural gas price is discounted compared to the benchmark price for natural gas in North America, the Henry Hub price. Henry Hub is the central pricing point for natural gas produced in the United States. The AECO-C and Henry Hub price differential narrowed in 2019 to US$1.29 per million BTU, down from US$1.95 per million BTU in 2018.

The discount for Canadian natural gas relative to Henry Hub exists in part because Alberta and other western Canadian natural gas fields are further away from US markets than are American suppliers and Canadian transportation costs are thus higher. This, combined with the fact that the US is currently the only market for Canada’s natural gas—Canada has yet to complete a single LNG export terminal, though one is under construction at Kitimat, British Columbia—means that AECO-C natural gas has traded at a discount of more than US$2.00 per million BTU in recent years, or about 60 per cent of the Henry Hub price.

However, lower natural gas prices in Western Canada can be beneficial for upcoming liquefied natural gas (LNG) projects designed to transport natural gas to Asia-Pacific markets because they will reduce the LNG plants’ input cost.

There is no standard global LNG pricing system. LNG contract prices are linked to international oil index prices, like Brent, and some are linked to regional natural gas indexes, such as Henry Hub. In recent years, a new benchmark has been developed for LNG
in Asia-Pacific markets—the Platts Japan/Korea Marker (JKM)—which is now the benchmark price for LNG deliveries in Japan and Korea. These two countries are currently the largest LNG importers globally, accounting for 33 per cent of the world’s LNG imports.

The price difference between North America’s leading benchmark Henry Hub spot price and LNG Asia spot prices was more than US$18 per million BTU at the beginning of 2021.⁴

Canada is a late entrant into the LNG market. Currently, 13 LNG projects are proposed and one is under construction in BC. Given that the demand for LNG in the Asia-Pacific market is currently being filled by traditional players such as Qatar and Australia, the entry of new players, such as Canada, will create a new dynamic in the coming years. The AECO-C benchmark natural gas price is lower than the Asia-Pacific benchmark LNG price, which could mean that buyers in the Asian-Pacific might turn to Canadian LNG, assuming the near-term completion of LNG projects in Canada.

4. Many factors influence final LNG prices. LNG pricing is not as transparent as oil pricing, as it involves many additional costs including the cost of feedstock (i.e., the natural gas cost), and liquefaction and shipping costs. The selling cost also must cover the seller’s capital and operating costs. Several studies have explored the viability of LNG projects and noted that the main drivers for LNG projects are capital costs, the availability of cheap natural gas feedstock, pipeline transportation costs, and operating costs.

Notes

This CEC Fact Sheet was compiled by Ven Venkatachalam and Mark Milke at the Canadian Energy Centre (www.canadianenergycentre.ca). All percentages in this report are calculated from the original data, which can run to multiple decimal points. They are not calculated using the rounded figures that may appear in charts and in the text, which are more reader friendly. Thus, calculations made from the rounded figures (and not the more precise source data) will differ from the more statistically precise percentages we arrive at using source data. The authors and the Canadian Energy Centre would like to thank and acknowledge the assistance of Dennis Sundgaard in reviewing the data and research for this Fact Sheet. Image credits: Seoul, South Korea, by Sesinando from Pexels.com

References (All links live and updated as of April 5, 2021)

AER (June 2020), Natural Gas Prices: Highlights of 2020 <https://bit.ly/3tzznnL>; BP (2020), Statistical Review of World Energy 2020 (69th edition) <https://on.bp.com/3s1sHhZ>; BP (n.d.), Outlook for Gas is More Resilient than for Either Coal or Oil <https://on.bp.com/30UY01V>; Canadian Energy Regulator (2017), Market Snapshot: LNG Projects have an Energy Efficiency Advantage Compared to Other LNG Producers in Warmer Locations <https://bit.ly/3djCr0O>; Canada Revenue Agency (n.d.), Definitions Related to the Fuel Charge <https://bit.ly/3rHgZbf>; EIA (2020, June 19), Higher Western Canada Spot Prices Limit U.S. Natural Gas Imports from Canada <https://bit.ly/3wifjIz>; International Monetary Fund (2021), Global price of LNG, Asia [PNGASJPUSDM], retrieved from FRED, Federal Reserve Bank of St. Louis< https://bit.ly/2RdCJyY>; IEA (2021), Gas Market Report Q1-2021 <https://bit.ly/30XrqMM>; IEA (2020), Gas 2020 <https://bit.ly/3f0Ns9A>; IEA (n.d.), Gas <https://bit.ly/3cdf49H>; Natural Resource Canada (n.d.), Natural Gas Facts <https://bit.ly/3eRSF3w>; J. Peter Findlay (2019), Canadian LNG Competitiveness, Oxford Institute of Energy Studies <https://bit.ly/3d2nr7u>; Claudio Steuer (2019), Outlook for Competitive Energy Supply, Oxford Institute of Energy Studies <https://bit.ly/3gGVl38>; Ven Venkatachalam and Mark Milke (2021), MIA – $130 Billion in LNG: The Global LNG Trade and Canada’s Missed Opportunities <https://bit.ly/2Qax7ow>.

Creative Commons Copyright

Research and data from the Canadian Energy Centre (CEC) is available for public usage under creative commons copyright terms with attribution to the CEC. Attribution and specific restrictions on usage including non-commercial use only and no changes to material should follow guidelines enunciated by Creative Commons here: Attribution-NonCommercial-NoDerivs CC BY-NC-ND.

The unaltered reproduction of this content is free of charge with attribution to Canadian Energy Centre Ltd. 

The Trans Mountain project has loaded petroleum on marine vessels off the south coast of B.C. with no spill incidents in nearly 65 years of tanker operations. Now, the expansion of the pipeline and marine terminal brings with it a landmark investment that will improve safety for all users including oil tankers, cargo ships, cruise liners and other vessels.

Increased shipping on the oil pipeline from Edmonton, Alta. to Burnaby, B.C. will increase exports through Trans Mountain’s Westridge Marine Terminal, from 5 to up to 34 tankers per month. But marine shipping experts don’t expect the project’s safe record to change with the additional movements.

“Vancouver sees about 3,000 to 3,500 deep sea vessels a year. So with the TMX, we’re probably looking at about a 10 to 12 per cent increase in traffic for the port,” says Captain Chris Badger, former chief operating officer of the Vancouver Fraser Port Authority.

Badger is one of eight specialists in marine shipping, regulation, risk management and engineering who contributed to a recent report by Resource Works on Trans Mountain oil tanker safety.

“It makes the port of Vancouver a fairly large port in North America, but quite small compared to large global ports,” he says. “Personally, I don’t really see [how] an increase of shipping from say 3,200 to 3,600 would have any material impact on safety.”

Even still, as part of the expansion Trans Mountain is investing $150 million on the largest-ever expansion of spill response on B.C.’s south coast. The funding goes to Western Canada Marine Response Corporation (WCMRC), which is responsible for responding to potential marine oil spills along all 27,000 kilometres of B.C.’s coastline. On average, WCMRC responds to about 20 spills each year.

“We compare oil spill response to fighting a forest fire,” says Michael Lowry, WCMRC’s manager of communications.

“In both cases, a lot of things are out of our control, such as weather, size of the spill or fire, and location. One aspect we can control, however, is response time. The quicker we get there, the more we can mitigate the impact, and that is one of the single biggest factors in addressing oil spills.”

Cutting spill response times

Trans Mountain’s investment to expand WCMRC capacity is expected to cut the response time required by Transport Canada to two hours from six in the Port of Vancouver and to six hours from 72 in shipping lanes. When new equipment and response bases are in place, WCMRC will have capacity to clean up a 20,000-tonne spill in 10 days, doubling the existing standard.

“To achieve these goals, we are building six new spill response bases along B.C.’s South Coast, including two 24/7 on-water bases,” says Lowry. “As well, we are doubling the size of our response vessel fleet from 44 to 88, and adding 135 full-time positions, primarily for response personnel.”

While the quantity of new vessels is impressive, the quality is also worth noting, such as the three purpose-built coastal response vehicles. These craft are long, wide, slow and steady, and made specifically to address the challenging West Coast weather.

“We are also bringing in an offshore supply vessel that is designed to serve offshore oil platforms,” Lowry says. “These vessels hold a lot of oil and have a large deck for equipment, and have proven very useful in spill response. Because there is no offshore industry on the West Coast, we haven’t had access to such vessels, so this will be a big change.”

Significant progress is being made on the new marine safety enhancements. To date, 10 new response vessels have been delivered and 85 additional employees hired, with construction underway on all six new bases. Lowry is confident that the work will be completed by the end of 2022, when the Trans Mountain expansion is expected to go into service.

Layers of safety protocols protect B.C.’s south coast

There are layers of safety protocols regarding oil tankers on B.C.’s south coast, says Resource Works executive director Stewart Muir.

“When a tanker moves from Burnaby with oil bound for China or Los Angeles, it has a skilled crew to guide it. The ship is under the control of a Canadian coastal pilot who watches everything onboard and navigates the tanker out past Victoria before turning the vessel back over to its captain,” he says.

Alongside the tanker, there are three modern, powerful tugboats designed especially for the Port of Vancouver, he says. These nimble craft can rotate 360 degrees and steer the vessel if it loses rudder control, thereby preventing a collision.

“In addition, there are systems and protocols watching over the vessel, such as the 24/7 marine operations centre atop a building in downtown Vancouver that acts like an air traffic control centre.”

Double hull tankers

Another layer of protection is the double hull design found in all modern oil tanker ships – a requirement following the Exxon Valdez oil spill off the coast of Alaska 32 years ago. Muir says Exxon Valdez transformed shipping safety for oil tankers.

“One major change was the move to a double hull structure that greatly reduces the risk of pollution. Today’s tankers have up to 18 cargo compartments,” Muir says.

“Imagine a bathtub filled with a bunch of jerry cans of gasoline. If someone takes a sledgehammer to the tub, they might crack the tub itself, but the liquid is still secure inside those containers…Many people think that if a tanker springs a leak it’s toast, but the true story is different.”

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