When Dow, one of the world’s largest chemical producers, plans to commit billions to build a state-of-the-art new complex, it has a comprehensive checklist of factors to consider and a list of suitors around the globe competing for the investment.

In 2023, after a lengthy review, Dow Canada president Diego Ordonez says Alberta made the most sense as the location for a new US$6.5-billion net-zero scope 1 and 2 emissions petrochemical complex.

The plant, to start operations in 2027, will produce polyethylene, the most widely used plastic.

“Even without a coastline, Alberta is in a great spot. There is a real demand for its energy as feedstock to manufacture the chemicals the world needs to continue to prosper,” says Ordonez, a self-described “renegade accountant” who has spent 35 years with Dow across the globe.

“We have operations around the world, so you have a list of possible locations when you are looking at the conditions that are necessary for this type of facility. You need a reliable supply of the raw material ethane, which you obtain through natural gas, and it has to be cost-competitive today and in the foreseeable future.”

The project also needs a site with a proven safety and reliability track record, he says.

Alberta’s Industrial Heartland region, near Edmonton, ticked all those boxes – including proximity to the right geology and infrastructure for carbon capture and storage (CCS), he says.

Reducing emissions with carbon capture and storage

A “significant factor” that supported Dow´s decision to invest in Canada was the financial support committed by the Alberta and federal governments through Alberta’s Petrochemicals Incentive Program and Canada’s CCS Investment Tax Credit, Ordonez says.

Dow’s project will feature Canada’s largest “blue” hydrogen production facility, under a more than $2 billion contract signed in August with Linde Canada. “Blue” hydrogen is the term for hydrogen generated from natural gas with operations that include CCS to reduce emissions.

Linde’s facility will be built to capture more than two million tonnes of carbon dioxide per year, or the annual equivalent of taking about 475,000 gasoline-powered vehicles off the road.

World plastics demand to triple by 2060

Reducing emissions from petrochemical projects is important as demand for plastics continues to grow.

“Petrochemicals are the building blocks of modern society. Clothing, tires, digital devices, packaging, detergents, healthcare and countless other everyday items that enable modern life are made from petrochemicals,” says a new report from Wood Mackenzie, a global consultancy specializing in analyzing energy data.

“With growing global populations and rising income levels, demand for petrochemicals is projected to increase.”

The Global Plastics Outlook, published by the Paris-based Organisation for Economic Co-operation and Development, forecasts the use of plastics globally will nearly triple by 2060, driven by economic and population growth.

New ethane supply

The announcement of more petrochemical production in Alberta is supported by increasing ethane supply.

Pipeline operator Wolf Midstream announced in July it will invest $1 billion to expand the capacity of its northeast Alberta Natural Gas Liquids system, bringing up to 60,000 barrels per day of ethane needed that will help meet growing petrochemical demand.

“What we are seeing with these large-scale investment decisions is companies are comfortable with the value proposition in Alberta. We have created or are creating economies of scale,” says Mark Plamondon, executive director of Alberta’s Industrial Heartland Association.

“We have the lowest cost feedstocks in North America and are competitive in the world on price. But we also have appeal with our carbon capture and sequestration infrastructure so companies can achieve both economic and environmental objectives. It is a one-two punch that is a game changer for us.”

Policy matters

But policy matters as much as steel in the ground, something Ordonez sees as differentiating Canada from other jurisdictions with clusters of heavy industries.

“Canada has market-based carbon pricing at both the federal and provincial level. That was an essential piece for us to decide to invest,” he says. “There is nothing similar in place in the USA or the Middle East.”

And work by industry has also resulted in government and regulatory support to support new investments in petrochemicals.

“For these investments to take place, you need a good active collaboration between industry and government. We have seen that in Alberta, and it has resulted in significant investments for Alberta,” says Greg Moffatt, executive vice-president of the Chemistry Industry Association of Canada.

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The recent announcements that two new carbon capture and storage (CCS) projects in Alberta will proceed sends the signal that the province is a prime location for investment in emissions reduction, says an industry expert. 

Shell and partner ATCO EnPower will proceed with a new CCS project at the Scotford refinery and chemicals complex near Edmonton, while on a smaller scale Entropy Inc. will add a second phase of CCS at its Glacier gas plant near Grande Prairie.  

Combined, the projects are expected to capture and store about 810,000 tonnes of CO2 per year, the equivalent of taking nearly 200,000 cars off the road annually. Entropy’s project is to start in 2026 and Shell/ATCO’s in 2028.  

“It’s all great news and hopefully more are to come,” says Beth (Hardy) Valiaho, vice-president of public affairs and international engagement for the International CCS Knowledge Centre.  

“Not only is Alberta open for business to do these projects, but we’ve got a lot to share to help others reduce emissions in their countries based on the lessons learned here.” 

More CCS needed 

CCS projects around the world today have the capacity to store about 50 million tonnes of CO2 per year. To meet climate targets, that needs to grow significantly. 

According to the Intergovernmental Panel on Climate Change, the International Energy Agency and others, by 2030 the world needs CCS to store one gigatonne of CO2 per year, rising to 10 gigatonnes by 2050. 

Valiaho says Alberta is drawing new CCS interest thanks to a mixture of favorable geology, close proximity of a variety of emitting industries, and a “hospitable” investment climate.  

“Western Canada has almost 400 billion tons of sequestration potential. And when you look at where the emissions are, most of the emissions in Canada, the larger sources, are centered over those storage opportunities,” she says. 

CCS in Alberta 

Alberta alone has more CO2 storage capacity than Norway, Korea, India, and double the entire Middle East, according to the Global CCS Institute.  

It also has a broad industrial presence including oil and gas production, refining, petrochemicals, cement and fertilizer. 

“CCS is a solution across industries. That’s why you see CCS popping up in Alberta, because of its diversified emission profile.” 

Since 2015, CCS operations in Alberta have safely stored roughly 13.5 million tonnes of CO2, or the equivalent emissions of more than three million cars. And now more CCS is on the way.  

New projects to proceed 

At the end of June, Shell announced it will proceed with the Polaris carbon capture project at its Scotford refinery and chemicals complex near Edmonton, and the nearby Atlas storage hub in partnership with ATCO EnPower.  

Both developments build on Shell’s experience at the Quest CCS project, also located at the Scotford complex, Shell Canada country chair Susannah Pierce told a press conference in July.  

Since 2015, Quest has stored about one million tonnes of CO2 per year, or a total of about 7.7 million tonnes.  

Starting near the end of 2028, Polaris is expected to capture up to 650,000 tonnes of C02 per year, transported to the Atlas storage hub by a 22-kilometer pipeline.  

Future phases at Atlas are expected to add capture operations at additional industrial facilities, helping build out Alberta’s strategy to develop multiple CCS hubs in the province.  

“We can be one of the first movers to attract those other emitters to be part of our agreement to sequester their emissions,” Pierce said. “For us, we see it as a competitive advantage.” 

Entropy Inc., a subsidiary of Advantage Energy, announced at the beginning of July it will proceed with its Glacier Phase 2 project, which is expected onstream in mid-2026 and will capture 160,000 tonnes of emissions per year from the Glacier gas plant near Grande Prairie. 

This builds on the company’s experience with the first phase of CCS at Glacier (47,000 tonnes per year), which achieved “first carbon” injected deep underground in August 2022.  

“This reduces the CO2 that would otherwise flow into the natural gas pipeline distribution system thereby reducing ultimate emissions at the burner tip,” Entropy vice-president of policy and carbon markets told CEC. 

The benefits of government support 

Valiaho says the new major project announcements show that government support can help drive new development. 

Alberta is finalizing its carbon capture incentive program, which covers up to 12 percent of eligible capital costs, while the federal government has implemented its CCS investment tax credit, which covers up to 60 percent of capture costs and 37.5 percent of the cost for transportation, storage or usage equipment. 

Both governments have supported CCS projects in the past: Shell’s $1.3 billion Quest project received $745 million from the Alberta government and $120 million from Ottawa, while the $1.2 billion Alberta Carbon Trunk Line received $495 million from Alberta and $63.2 million from the federal government. 

Government support continues to be important for what Valiaho calls “the next wave” of CCS development.  

“The projects are still quite expensive, and it’s not just the capital costs, but it’s also the operating costs,” she says.  

It can also be daunting for companies to proceed with a large investment in CCS because capturing and storing CO2 is an entirely different operation than their core business of, say, processing oil or producing cement, Valiaho says. 

“This isn’t a technology you buy off a shelf and over time the costs reduce themselves. This is something that has to have iterative applications, and it’s always integrated into your unique circumstance,” she says.  

“The great thing about CCS is it enables industry to continue while reducing its emissions. And what ends up happening is you are against emissions as opposed to against any one industry, and that’s really good for jobs and sustaining the economy.”   

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Suncor Energy is nearing completion of its upgraded cogeneration project, providing a boost to Alberta’s electrical grid while reducing emissions intensity for the oil sands giant.

The $1.4 billion Coke Boiler Replacement Project is swapping out three aging petroleum coke-fired boilers with two high-efficiency natural gas cogeneration units at Suncor’s Base Plant, 25 kilometres north of Fort McMurray.

Cogeneration units are crucial cog for oil sands operations. They generate heat to extract bitumen while producing electricity and steam.

Announced in 2019, the new units remain on course to begin operations in late 2024. They will produce approximately 800 megawatts to Alberta’s electric grid while reducing the intensity of greenhouse gas (GHG) emissions for both Suncor and the oil sands industry as a whole.

Kevin Birn, a Calgary-based analyst who has tracked GHGs in the energy industry for more than a decade, sees the environmental benefits of moving on from coke boilers, a technology that dates back to the 1960s.

“Petroleum coke is roughly two times as carbon intense as combusting natural gas so this project can drive emissions improvements for both Suncor and the industry,” says Birn, global head for the Center of Emissions Excellence and chief analyst Canadian oil markets for S&P Global.

“This move retires petroleum coke use from one of the two remaining oil sands operations that burn the material.”

Use of petroleum coke, a byproduct from upgrading bitumen to synthetic crude oil, currently accounts for about 11 per cent of the total emissions from the oil sands mining sector. S&P Global Commodity Insights estimates roughly five million megatonnes of CO2 annually, or about 10 kilograms per barrel of marked synthetic crude produced by oil sands miners.

While Suncor’s natural gas consumption will increase when the new units come online in the fourth quarter, they will also turn the company into the third largest power producer in Alberta, supplying approximately seven per cent of the province’s current electricity demand. Suncor’s natural gas cogeneration units will have a lower GHG intensity than the current grid average.

The environmental benefits of “fuel switching” from petroleum coke to natural gas extend beyond reduced GHGs. In a filing with the Canadian Environmental Assessment Agency in December 2017, Suncor estimated its new cogeneration units would reduce sulphur dioxide (SO2) emissions by 46 per cent, nitrogen oxide (NOX) emissions by 17 per cent and particulate matter emissions by 66 per cent. It would also cut freshwater use by 35 per cent.

The unused petroleum coke will likely be stored rather than combusted, Birn says.

“This already happens at integrated oil sands operations which produce petroleum coke,” Birn says. “Operators are required to store petroleum coke as a potential fuel source but the vast majority is not marketed given the distance to market.

“Over the entire life of the oil sands, nearly three quarters of the produced pet coke has been stored. Storing it does allow for more valuable future potential uses, such as being part of the manufacture of carbon fibre.”

Syncrude has also developed a technology using petroleum coke produced at its operation to treat process water. The treatment is similar to using a home water filter. The petroleum coke, which is almost pure carbon, acts as a filter to remove constituents in the water, such as naphthenic acids.

“Technology will continue to play a key role to help the industry meet its environment goals as well as improving production,” Birn says. “This decision by Suncor is a good example of that.”

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The first oil sands project using a technology designed to reduce emissions per barrel by nearly half is officially up and running.  

Imperial Oil CEO Brad Corson confirmed the company started operations at its Grand Rapids project on December 1, one year ahead of schedule. 

“Grand Rapids production is expected to achieve an emissions intensity that is up to 40 per cent lower compared to existing cyclic steam technology in use today,” Corson told analysts on a call to discuss the company’s 2023 results. 

The project is at Imperial’s Cold Lake oil sands operation, which has produced oil since the 1980s.  

The new technology is an advancement in steam assisted gravity drainage (SAGD), which is responsible for nearly half of today’s oil sands production.   

“This is a big deal. This is really good to see, and I hope to see continued momentum,” said Bryan Helfenbaum, associate vice-president of clean energy with Alberta Innovates. 

In so-called solvent assisted SAGD, light hydrocarbons or “solvents” like diluent, propane or butane are injected deep underground along with steam to melt and mobilize thick bitumen deposits.  

It’s a bit like adding a thinner to a heavy paint.   

After an initial start-up phase expected to last through the first quarter of 2024, production is targeted to ramp up to 15,000 barrels per day. 

Corson says the company “has a whole pipeline” of solvent deployment potential at Cold Lake.   

“We’re continuing to explore future generations of opportunities that will allow us to not only grow production but do that in a lower cost way and also, quite importantly, with lower emissions intensity,” he says. 

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Oil and gas producers in Alberta spent substantially more than required in 2022 cleaning up inactive wells, facilities and pipelines, according to a new report. 

The Alberta Energy Regulator (AER) set the first industry-wide minimum “closure” spending requirement at $422 million.  

Updated numbers released this week show producers spent over $696 million, about 65 per cent more than the regulator required. 

An additional $568 million of closure work was conducted by the industry-funded Orphan Well Association and through Alberta’s site rehabilitation program.  

The new mandatory quotas determine the minimum level of work a company must conduct primarily to decommission and reclaim inactive wells.  

First an inactive well (defined as one that has not been used for six months or a year, depending on the well and what it is being used for) is abandoned, and then reclaimed.  

A well is successfully abandoned after it is cleaned, plugged with cement, cut to a minimum of one meter below the surface, and covered with a vented cap. After abandonment comes reclamation, where the land around the well is returned to the equivalent of its original state. 

Industry abandoned 10,334 inactive wells, pipelines and facilities in 2022 (including 9,687 wells) – nearly double the amount abandoned in 2019 and 2020, the AER reports.   

Reclamation activity also accelerated, with the AER issuing 4,100 reclamation certificates, an increase of approximately one-third compared to 2021. 

The regulator reports that 16.8 per cent of licensed wells in Alberta are now considered inactive, down from 21.3 per cent in 2020. And 29.7 per cent of licensed wells are reclaimed, up from 27.7 per cent in 2020.  

The new mandatory closure spending is part of Alberta’s Inventory Reduction Program, which was introduced in 2020 to decrease the number of inactive oil and gas wells, facilities and pipelines in the province. It applies to closure of operations other than oil sands mining, which is handled under the Mine Financial Security Program.   

A central component of the reduction program is an approach called Area Based Closure.  

Essentially that’s when companies group together wells that need to be cleaned up based on where they are located so that work activities can focus on one area. This allows for more efficient use of resources like workers and equipment and is supported by an online mapping tool to help producers and service providers work together.  

The AER estimates area-based closure can provide cost savings of up to 40 per cent.  

The minimum closure spending requirement for 2023 is set at $700 million and will be $700 million again in 2024. 

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New data released in 2023 shows the progress Canada’s oil and gas industry is making to reduce its environmental footprint.  

From emissions to water use and reclamation, here are some key performance statistics.  

1. Methane emissions reduction target achieved three years ahead of schedule 

Photo courtesy Tourmaline

The Alberta Energy Regulator (AER) released data in November showing that oil and gas producers in the province achieved the target of reducing methane emissions by 45 per cent compared to 2014.  

The milestone was achieved in 2022, three years ahead of the 2025 government deadline.  

Reducing methane emissions comes primarily from reducing small leaks from valves, pump seals, and other equipment, as well as reducing flaring and venting.   

2. Oil sands emissions stay flat despite production growth  

Oil sands steam generators. Photo courtesy Cenovus Energy

An updated study by S&P Global in August found oil sands emissions did not increase in 2022 even though production grew. 

It’s a significant first that indicates oil sands emissions may start decreasing sooner than previously expected, said Kevin Birn, S&P Global’s vice-president of Canadian oil markets.  

Total oil sands emissions were 81 megatonnes in 2022, nearly flat with 2021 despite a production increase of about 50,000 barrels per day.  

In 2022, S&P Global predicted peak oil sands emissions around 2025. The new findings indicate it could happen faster.  

3. Producers spend millions more than required on oil and gas cleanup 

Photo courtesy Alberta Energy Regulator

Oil and gas producers in Alberta spent significantly more than required in 2022 cleaning up inactive wells, facilities and pipelines, the AER reported in October.  

The regulator’s industry-wide minimum “closure” spend for 2022 was set at $422 million. But the final tally showed producers spent $685 million, or about 60 per cent more than the regulator required.  

Industry abandoned 10,334 inactive wells, pipelines and facilities in 2022 – nearly double the amount abandoned in 2019 and 2020, the AER reported.   

Reclamation activity also accelerated, with the AER issuing 461 reclamation certificates, an increase of one third compared to 2021.  

The regulator reports that 17 per cent of licensed wells in Alberta are now considered inactive, down from 21 per cent in 2019. And about 30 per cent of licensed wells are now considered reclaimed, up from 27 per cent in 2019.   

4. Oil sands reclaimed land growing  

Wetland in reclaimed area in the Athabasca oil sands region. Photo by Greg Halinda for the Canadian Energy Centre

Data released by Canada’s Oil Sands Innovation Alliance highlights the growing spread of the industry’s reclaimed land. 

As of 2021, oil sands operators had permanently reclaimed 10,344 hectares, the equivalent area of more than 20,000 NFL football fields – a 16 per cent increase from 2019. 

Of this, 1,296 hectares (about 2,500 NFL football fields) is permanently reclaimed to wetlands and aquatics.  

5. Fresh water use per barrel declining 

Photo courtesy Cenovus Energy

New data on water use in Alberta’s oil and gas industry released in December shows producers continue to reduce the use of fresh water from lakes, rivers and shallow groundwater

The oil and gas industry used less than one per cent of Alberta’s available fresh water in 2022, the AER reported.  

Thanks primarily to increased water recycling, fresh water use per barrel in Alberta oil and gas has decreased by 22 per cent since 2013.  

Overall, 82 per cent of water used in Alberta oil and gas in 2022 was recycled; 80 per cent in oil sands mining, and 90 per cent in drilled or “in situ” oil sands production.  

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The Canadian Energy Centre continues its multifaceted work to promote Canada as the world’s supplier of choice for responsibly produced energy.  

Read our latest update to learn about our research, marketing, editorial, multimedia and advocacy programs, including:  

• Our reach across Canada and internationally
• Results of marketing campaigns 
• Research topics 
• Editorial themes 
• Graphics and videos  
• Advocacy activity 

Participating in a recent trade mission to China has strengthened Karen Ogen’s view of the opportunity for B.C. liquefied natural gas (LNG). 

For the CEO of the First Nations LNG Alliance, one of 10 Indigenous business leaders in the Canada China Business Council’s trade mission to Beijing in late October, the opportunity was as obvious as the grey smog that blankets the air above China’s capital city on most days. 

“So much of the problem with smog and air quality stems from using coal-fired plants to generate electricity,” says Ogen, a former elected chief and councillor of the Wet’suwet’en First Nation.  

Researchers have found that switching Chinese coal plants to natural gas from Canada could reduce emissions by up to 62 per cent. 

“The Chinese don’t view LNG as a fossil fuel. They see it as an important part of moving towards carbon neutrality,” Ogen says. 

“There are huge opportunities for LNG in China and other Asian markets, especially for the coastal nations in British Columbia. The need is there, and the appetite is there. It’s up to us to take advantage of it.” 

Ogen previously took trips to China between 2015 to 2018. The most recent trade mission was organized by the Canada China Business Council specifically for Indigenous businesses, organizations and leaders to build connections and partnerships to develop export markets and sources of investment to facilitate exports. 

Ogen said the delegation gained valuable insights into new forces shaping China in the post-pandemic era, notably around using social media platforms such as TikTok as part of their marketing and e-commerce outreach to the Chinese market. But she remains struck by the appetite for LNG as a lever to lower emissions as energy demand rises. 

“China produces 30 per cent of the world’s greenhouse gas emissions — it’s the world’s largest emitter and they are committed to addressing that,” Ogen says. 

The U.S. Energy Information Administration projects natural gas demand in the Asia Pacific region will increase by 55 per cent in the next three decades, reaching 54 trillion cubic feet in 2050. 

Canada can make a meaningful difference in helping reduce emissions by supplying Asian markets with LNG, she says. 

“Converting coal-fired plants in China to LNG produced in Canada would make a bigger impact on greenhouse gas emissions than anything we do in Canada,” Ogen says.  

“Canada needs to think globally when it comes to climate change.” 

The United States already has seen this opportunity and is addressing it by aggressively expanding LNG exports. Already one of the world’s largest LNG exporters, there are five new LNG projects being built in the U.S. 

Canada’s first LNG project is under construction with first exports targeted by 2025. Two Indigenous communities on the B.C. coast are advancing their own proposed terminals, Cedar LNG and Ksi Lisims LNG.  

Ogen doesn’t want to see Canada or B.C.’s coastal First Nations shut out of the opportunities she saw on the trade mission. 

“The message we received from China’s officials was very clear. They are prepared to do business with Canada and Canada’s Indigenous business community. There are opportunities for investment,” she says.  

“But we need governments to work with us to realize those opportunities. If we pursue them seriously, there are real economic benefits for Canada and First Nations.” 

And the five-day trade mission has convinced Ogen about the need to address the barriers for Canadian LNG. 

“We have a real opportunity to help address climate change while benefiting First Nations,” she says. “It makes too much sense for us not to fight for this.” 

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From prosperity for remote Indigenous communities in northern British Columbia to lowering emissions in Asia to help fight climate change, the benefits of the proposed Ksi Lisims LNG project would extend regionally, nationally, and globally, according to project documents.   

The Nisga’a Nation and its partners in the project reached a significant milestone this week with the filing of an application for an environmental certificate, moving it into a critical regulatory phase.  

UPDATE: The Ksi Lisims LNG project received its environmental assessment certificate to proceed from the B.C. government on September 15, 2025.

The Ksi Lisims (pronounced “s’lisims”) floating terminal, located in Nisga’a territory near B.C.’s border with Alaska, would export up to 12 million tonnes of LNG per year. By using electricity and carbon offsets it is designed to be net zero within three years of startup, targeted for 2027.  

The partners estimate that one tonne of LNG exports from B.C. reduces four tonnes of emissions in Asia by reducing reliance on coal-fired power.  

Here’s a look at the benefits of Ksi Lisims, as stated in the environmental certificate application: 

LOCAL: Create economic self-determination for the Nisga’a Nation and improve the quality of life for Nisga’a citizens through the provision of new revenue and royalty streams, training, education, employment and contracting opportunities for Nisga’a citizens, while also providing indirect benefits such as improved community infrastructure and marine emergency response in the vicinity of the site. 

REGIONAL: Create direct and indirect economic benefits for other Indigenous nations in the region, as well as other communities in northwest B.C., Alberta, and Canada, including skills training, local employment, contracting and procurement. 

NATIONAL: Provide tax revenue that will support Indigenous, provincial and federal objectives to improve health, education, transportation infrastructure and other social benefits. 

GLOBAL: Low carbon LNG supports the global transition away from more carbon intensive forms of energy while providing improving energy security and reliability in global markets. 

Filing the environmental certificate application kicks off a 180-day comment period, after which Ksi Lisims will amend its application and file a final version. The B.C. Environmental Assessment Office then has 150 days to consider the application and issue notice on whether the project can proceed.  

Following that timeline, that decision should be issued around September 2024.  

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An additional $400 billion investment in liquefied natural gas (LNG) projects around the world is needed over the next decade to ensure energy security and achieve emissions reductions, according to a new report by Wood Mackenzie.  

Without increased LNG supply, it said Asian countries in particular will continue to rely on high-emitting coal as they grow power generation. 

“On a global scale, limited supplies of LNG risks stalling progress towards 2050 net zero targets in the near term,” says the report by Wood Mackenzie and Petronas, one of the joint venture owners of the LNG Canada project.  

The fallout from Russia’s invasion of Ukraine rerouted LNG shipments from Asia to Europe, contributing to record coal consumption in 2022, analysts noted.  

“A key pillar of the energy transition is to reduce the consumption of coal. A critical step in that transition is to shift power production from coal to much lower-emissions gas. The shift helps drive immediate decarbonization while renewables, energy storage, and other clean energy technologies scale-up.” 

Power generation from natural gas reduces emissions by half on average, according to the International Energy Agency (IEA). LNG from Canada can deliver an even bigger decrease, reducing emissions by up to 62 per cent, according to a 2020 study published in the Journal for Cleaner Production. 

Global natural gas use is rising, driving increased demand for LNG. The U.S. Energy Information Administration’s latest outlook projects natural gas consumption will rise to 197 quadrillion BTU in 2050, up from 153 quadrillion BTU in 2022.  

“Gas can be used to not only replace coal for power generation, but also to provide fuel for blue hydrogen production, and as an essential source of flexibility as electricity grids incorporate increasingly large amounts of intermittent renewable generation,” Wood Mackenzie said.  

“Gas also plays a critical role in non-power sectors such as commercial and residential heating, as a feedstock for chemicals and fertilizers, and as an energy source for metals, cement, and other manufacturing processes.” 

Canadian LNG has advantages in a lower emission world, the report said.  

“Canada’s western ports are ideally positioned to supply growing Asian demand because its shipping routes aren’t dependent on an uncongested Panama Canal. The country is also poised to produce some of the lowest-emission LNG in the world,” Wood Mackenzie said.  

The low emissions per tonne of LNG in Canada come from shorter shipping distances to customers, a colder climate, the use of hydroelectricity, and methane emissions reduction from upstream natural gas production. 

Once it starts operating in 2025, LNG Canada will have emissions intensity of 0.15 per cent CO2 per tonne, less than half the global average of 0.35 per cent per tonne, according to Oxford Energy Institute.   

Proposed Indigenous-led project Cedar LNG would have emissions intensity of 0.08 per cent, and smaller-scale Woodfibre LNG would have emissions intensity of 0.04 per cent.   

“The gas and LNG supply and demand mismatch that spawned the current energy crisis and stalled energy transition progress can’t be repeated,” Wood Mackenzie said.  

“This will require a long-term commitment to expanding capacity to ensure reliable, increasingly low-emission, and affordable LNG that won’t be upended by future geopolitical and economic disruptions.” 

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