The report highlights a rapidly evolving energy system, driven by rising electricity demand, continued reliance on natural gas, and the growing complexity of balancing affordability, reliability, and emissions reductions.

The CER’s Energy Futures analysis is not a prediction, but rather a series of scenarios exploring how Canada’s energy mix could evolve under different economic, technological, and policy conditions.

Still, one conclusion is clear: electricity demand is expected to surge, while natural gas remains a key part of the energy system—even as the country works toward lower emissions.

That finding aligns with a growing body of industry and policy analysis pointing to the same dual trend.

Electricity demand in Canada is rising quickly, driven by electrification of transportation, industry, and buildings. A recent industry report described the situation as requiring Canada to “build big again,” warning that the country may need to dramatically expand its grid to keep pace with demand growth.

At the same time, reliability concerns are emerging. A North American reliability assessment cited by Global News found Canada’s power grid is under increasing strain, with demand expected to outpace new supply in several regions later this decade.

Against that backdrop, natural gas is expected to continue playing a significant role, particularly as a flexible source of power generation that can support intermittent renewables like wind and solar.

Canada’s broader energy landscape is already moving in that direction. Federal data shows renewable electricity is growing, but oil and natural gas remain foundational to the economy and energy system.

The CER report suggests this dual-track evolution—more electricity, but continued natural gas use—will define Canada’s energy transition over the coming decades.

That reflects a broader shift in how policymakers and industry are framing the transition: not as a simple replacement of fossil fuels, but as a more complex transformation of the entire energy system.

Recent federal policy signals point the same way. Ottawa has emphasized the need to invest in grid infrastructure and energy systems to maintain affordability and reliability while transitioning to lower-carbon sources.

The challenge, analysts say, is scale.

Electrification alone could require doubling or even tripling parts of Canada’s electricity system, while maintaining reliability during extreme weather events and peak demand periods. At the same time, natural gas infrastructure continues to expand in some regions to meet growing demand and support economic activity.

This creates a tension at the heart of Canada’s energy future.

On one hand, electricity—particularly from low-emission sources—is expected to do much of the heavy lifting in reducing emissions. On the other, natural gas remains critical for reliability, industrial use, and export opportunities.

The CER’s outlook underscores that both trends are likely to unfold simultaneously.

It also reinforces a key message for policymakers: the transition will require significant investment, regulatory reform, and coordination across provinces and sectors.

Canada’s energy system is already diverse and regionally fragmented, with provinces relying on different mixes of hydro, nuclear, fossil fuels, and renewables. Integrating these systems—while expanding capacity and reducing emissions—will be a major undertaking.

The CER’s modelling highlights the uncertainty involved. Long-term energy forecasts depend on assumptions about technology costs, climate policy, global markets, and consumer behaviour, all of which can change rapidly.

Even so, the direction of travel is becoming clearer.

Electricity is poised to become the backbone of a lower-emissions economy. Natural gas, meanwhile, is expected to remain an important—if evolving—part of the mix.

For Canada, the question is no longer whether the energy system will change, but how quickly—and whether the country can build the infrastructure needed to support that transformation.

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The Canada Energy Regulator’s Market Snapshot: The rise of Canada’s carbon dioxide removal industry highlights how evolving policy frameworks, abundant natural resources and emerging technology developers are laying the foundation for an industry that may play an indispensable role in meeting Canada’s climate commitments.

CDR refers to a suite of technologies and processes that remove carbon dioxide (CO₂) from the atmosphere and store it permanently or use it in long-lived products. This can include direct air capture (DAC), biomass carbon removal and storage (BiCRS), enhanced rock weathering, carbon mineralization and ocean-based removal techniques. According to the Intergovernmental Panel on Climate Change, virtually all scenarios that limit global warming to 1.5°C involve large-scale deployment of CDR alongside deep emissions cuts.

The CER snapshot lays out how Canada’s combination of policy support, renewable energy resources, and geological storage opportunities creates conditions favourable to scaling such technologies domestically. It notes that 78 Canadian companies are currently active in the sector with 48 active and planned CDR projects, data visualized on the Carbon Removal Canada Carbon Console platform.

Federal climate policy is starting to reflect the importance of CDR. A key plank of Canada’s broader climate strategy is using government procurement to help create early demand for carbon removal services, with official commitments to purchase CDR projects that reduce government emissions. Such demand signals are crucial to making early projects economically viable.

Outside government, industry groups are pushing for a more robust policy framework. The Carbon Business Council, which represents more than 100 carbon removal companies, published a policy primer recommending a suite of federal actions — including stable tax incentives, clear regulatory frameworks and streamlined permitting — to unlock tens of billions in economic value and cement Canada’s leadership in the emerging global market. “Canada is positioned to lead on carbon removal with its abundant renewable energy, durable geological storage and expansive coastlines,” a council spokesperson said in a recent overview.

Independent analyses point to major economic upside if Canada scales its CDR industry. A 2023 report from Carbon Removal Canada, for example, estimated that widespread deployment of carbon removal solutions could create more than 300,000 jobs and add roughly $143 billion in GDP by 2050, all while advancing national climate goals.

Canada’s CDR landscape spans a range of technologies and business models. Montreal-based Deep Sky is one of the emerging players in the direct air capture space, developing pilot projects designed to capture hundreds of thousands of tonnes of CO₂ annually using a range of capture pathways and geological storage options.

Elsewhere, CarbonCure Technologies, originally founded in Halifax, has been commercializing carbon mineralization technology that injects captured CO₂ into concrete, permanently storing it while improving strength — a model that has seen adoption in buildings and infrastructure projects worldwide.

Beyond land-based removal, recent reports have underscored the potential of marine carbon dioxide removal (mCDR) approaches, which leverage Canada’s vast coastlines. Analysis from the Ocean Supercluster suggests that ocean-based approaches could create tens of thousands of jobs and contribute significantly to long-term removal capacity if developed responsibly.

Despite the momentum, significant hurdles remain. Most CDR technologies are still at early commercial scales and costly relative to traditional emissions reductions, meaning sustained public and private investment will be necessary to drive down costs and build infrastructure at scale. The energy requirements for processes like direct air capture, potential environmental impacts of certain ocean-based methods, and the need for robust carbon storage networks are among the challenges noted by both the CER and independent research.

The CER snapshot also points to land-use conflicts, permitting issues and the need for transparent measurement, reporting and verification (MRV) systems that ensure CO₂ removals are real, permanent and additional.

Internationally, demand for carbon removal solutions is rising as companies and countries seek to address hard-to-abate emissions in sectors like steel, aviation and heavy industry. Global consultancies estimate the CDR market could be worth more than US$1 trillion by mid-century, a figure that underscores why countries with strong natural advantages — including renewable energy, geological storage and research capacity — are vying to establish early leadership.

Canada’s relative strength in these areas — blended with emerging policy and market signals — has attracted interest from major multinational corporations seeking removal credits as part of their climate strategies. Names such as Microsoft, Amazon, Shopify and Google have engaged with Canadian initiatives, reflecting a cross-sector push into removal markets.

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The CER examined throughput and capacity data for three major pipeline systems — Enbridge Mainline, Keystone and Trans Mountain — which together transport crude oil from the Western Canadian Sedimentary Basin (WCSB) to domestic and international markets. Combined monthly throughput across the systems exceeded 4.6 million barrels per day (MMb/d) at several points in 2024 and remained near that level through mid-2025.

Enbridge Mainline, Canada’s largest crude oil pipeline system, continued to operate at high utilisation levels throughout the period. Average throughput in 2024 was about 3.06 MMb/d, with volumes remaining strong into early 2025. Monthly throughput peaked above 3.2 MMb/d during winter months, when demand for condensate used in oil sands production increased.

The CER noted that throughput occasionally exceeded reported capacity due to operational factors such as changes in product mix and temporary efficiency gains.

Keystone pipeline throughput also remained high, averaging more than 600,000 barrels per day in 2024. An oil release in North Dakota in early 2025 temporarily reduced flows, but throughput recovered quickly. By June, volumes were again close to pre-incident levels, with utilisation typically ranging between 94 and 100 per cent.

The most significant structural change to Canada’s pipeline network came with the completion of the Trans Mountain Expansion Project in May 2024. The expansion nearly tripled Trans Mountain’s capacity, from about 300,000 barrels per day to roughly 890,000 barrels per day.

Following the expansion, Trans Mountain throughput rose sharply. Monthly volumes ranged between about 670,000 and 740,000 barrels per day in late 2024 and averaged roughly 730,000 barrels per day in the first half of 2025. The CER said the expanded system has eased long-standing capacity constraints and increased flexibility in routing Canadian crude.

The TMX expansion meant increased access to tidewater and has enabled Canada to significantly increase crude oil exports to overseas markets, particularly in Asia. Statistics Canada data show that crude exports through British Columbia rose sharply after TMX entered service, with shipments reaching destinations including China, South Korea, Japan and Singapore.

While the United States remains Canada’s dominant export market, the ability to move oil westward has allowed producers to access higher-value international markets and reduce reliance on a single customer. CER analysis indicates that the expansion has also contributed to a decline in crude-by-rail shipments, as pipeline capacity became more available and cost-competitive.

Reuters has reported that Asian refiners have shown growing interest in Canadian heavy crude blends since TMX entered service, attracted by supply diversification and competitive pricing relative to other heavy grades. Analysts cited by Reuters say the expanded pipeline has improved Canada’s negotiating position by narrowing price discounts and giving producers optionality when U.S. markets are saturated.

Despite strong utilisation, commercial conditions around the expanded Trans Mountain system continue to evolve. Reuters has reported that the pipeline operator recently revised its longer-term throughput forecasts downward, citing slower uptake of spot capacity and ongoing negotiations with shippers over tolls.

Those reports underscore that pipeline utilisation depends not only on physical capacity, but also on toll structures, crude price differentials and shipping economics — particularly for long-haul exports to Asia, which face higher transportation costs than shipments to U.S. markets.

High pipeline utilisation reflects strong Canadian crude production. The CER previously reported that Canada set new production records in 2024, with output remaining elevated into 2025, driven largely by oil sands operations.

Reuters has also reported that major Canadian producers expect production to remain robust through the middle of the decade, supporting continued demand for pipeline capacity even amid oil price volatility.

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At the beginning of November, total nationwide propane storage stood at 1,561 thousand cubic metres, 19.7 per cent below the five-year average and just 1.6 per cent under the five-year minimum.

The regional picture is similarly tight. In western Canada, storage reached about 6.46 million barrels — a figure 12.6 per cent below the five-year average, though 2.4 per cent above the five-year minimum. In Ontario, propane stocks stood at roughly 3.36 million barrels, 30.6 per cent below the provincial five-year average despite being 7.4 per cent above the minimum threshold.

In stark contrast, Canada’s natural gas storage is robust. As of 1 November 2025, total gas inventory reached about 1,099 billion cubic feet (Bcf), marking 2.0 per cent above the five-year maximum. In western Canada, storage reached 760 Bcf, 3.9 per cent above the historical high; in eastern Canada, stocks were 339 Bcf, just 0.6 per cent below the five-year average.

Seasonal dynamics, production, and export shifts

The divergent trajectories for propane and natural gas reflect different underlying market dynamics. For natural gas, persistently strong production — particularly from liquids-rich formations like the Montney in British Columbia and Alberta — continues to bolster supply. At the same time, slower-than-expected export volumes from new liquefied natural gas (LNG) capacity, mild summer and early-autumn weather, and pipeline constraints have contributed to elevated storage levels.

Conversely, propane — a byproduct of natural gas processing — has faced tightening supply relative to demand. While overall production remains broadly stable, elevated exports from British Columbia and overland shipments to U.S. and Mexican markets have drained inventories. This has reduced the buffer of stored propane heading into winter, increasing the risk of tightness if demand spikes.

Winter demand, weather uncertainty, and risk factors

Propane and natural gas are both widely used for heating and other uses during Canada’s winter, making inventory levels critical. The CER notes that demand surge from cold weather — or unexpected swings in temperature — could rapidly draw down propane (and in some regions, gas) inventories, potentially tightening supply and pushing up prices.

The 2025 winter outlook adds further uncertainty. Forecasts from Environment and Climate Change Canada (ECCC) suggest a higher probability of warmer-than-average conditions for November through January, which may temper heating-fuel demand. In contrast, the U.S. National Oceanic and Atmospheric Administration (NOAA) projects a cooler-than-normal winter linked to La Niña patterns — a development that could boost heating demand across much of North America.

If colder weather prevails, propane markets in particular could come under pressure given already low inventories. For natural gas, the ample storage offers greater buffer, but demand surges could still strain regional distribution systems if withdrawals accelerate sharply.

Implications for supply, exports and pricing

The contrasting storage positions for propane and natural gas may have ripple effects on Canadian energy markets. For natural gas, strong storage — paired with record production — enhances Canada’s competitive position for domestic demand, exports, and upcoming LNG export commitments. It also offers a cushion against price volatility, especially if winter demand remains moderate or exports ramp up gradually.

But for propane, the tight inventory picture increases vulnerability. If demand surges this winter — whether for heating, agricultural use, or exports — supply could become constrained. That may lead to higher wholesale or retail prices, particularly in regions heavily reliant on stored propane for winter heating.

Export markets could also feel the pressure: with tighter domestic supply, Canada may find it harder to meet external demand for propane, prompting reprioritization toward domestic needs or increased imports.

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Monthly throughput and available capacity on the NGTL system

Much of the WCSB’s output must transit through key delivery points such as East Gate 1 and West Gate 2 on the NGTL system, upstream of James River, and border-points on Alliance (Elmore) and Westcoast (Huntingdon).  The report notes that available capacity and throughput on the NGTL system have steadily increased in recent years, and also display a clear seasonal uptick in winter—when colder ambient temperatures compress gas molecules and demand for heating rises.

Monthly throughput and available capacity on Alliance and Westcoast Pipelines

This high-utilisation environment reflects a supply-side picture in western Canada that remains robust: producers are pumping, export pipelines are loaded, and market demand in the U.S. and beyond remains a primary driver.

The supply-demand dynamic: strong flows, underlying constraints
On the supply side, western Canada’s sustained production is feeding export corridors at full speed. The ability to ship large volumes reflects not only strong upstream activity but also favourable weather conditions in the U.S. that pushed heating demand. Cold spells in export markets added pressure to the pipeline system, enabling higher throughput.

Yet on the demand side and downstream of the pipeline system, the story is more nuanced. While export flows remain high, constraints are emerging. The CER report cautions that throughput occasionally exceeds reported “available capacity” because capacity estimates may not fully capture real-time operational conditions such as ambient temperature shifts, downstream bottlenecks or unplanned outages. This suggests that while flows are strong, the margin for additional throughput may be thin, and the system remains sensitive to weather, supply disruption or downstream demand shifts.

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Every time you turn on a light switch, a complex system delivers electricity from power plants to your home. This system, the electric grid, includes the bulk power system (BPS) and the distribution system, and it works 24/7 to keep the lights on.

What is the bulk power system (BPS)?

The electric “grid” delivers electricity from producers to consumers. It includes the:

1. Generation system
2. Transmission system
3. Distribution system

The “Bulk Power System” (BPS) includes the generation and transmission systems. The North American Electricity Reliability Corporation (NERC) defines the BPS as “the facilities and control systems necessary for operating an interconnected electric energy transmission network (or any portion thereof); and electric energy from generation facilities needed to maintain transmission system reliability. The term does not include facilities used in the local distribution of electric energy”^Footnote 1.

Maintaining the reliability of the BPS is crucial to ensuring the overall reliability of the electric grid.

Figure 1: Bulk Power System (BPS)

BPS reliability

Most Canadian provinces follow NERC’s reliability standards. Each province is responsible for maintaining the reliability of its BPS. NERC defines BPS reliability in terms of two parts:

1. Adequacy^Footnote 2 means having enough resources to provide electricity at the proper voltage and frequency to continuously meet customer demand, virtually all the time. This is more generally referred to as resource adequacy^Footnote 3 and is evaluated at the planning stage. In this planning stage, power system planners look ahead to predict how much electricity will be needed in the future, and make sure enough power plants and other resources will be available to meet that need, including some extra capacity for emergencies.
2. Operating reliability^Footnote 4 refers to always keeping the power on—the ability of the electric system to withstand sudden and unexpected disturbances like short circuits or unplanned outages^Footnote 5. This is an issue that is managed in real time in the operational stage.

A reliable BPS is one that meets both these conditions, virtually all the time. An indicator of grid reliability difficulties is the Energy Emergency Alert (EEA). EEAs are alerts sent out by system operators during major grid events. These alerts are classified at different levels by NERC; level 3 being the most critical^Footnote 6, indicating the highest threat to grid reliability. Considering one of the provinces, Alberta for example, EEA events increased notably during 2022-2023, with four EEA 2 events and seven EEA 3 events in 2022. The trend continued into 2024 with six EEA-3 events, indicating sustained grid stress during this period.

Figure 2: Frequency of EEA 2 and EEA 3 events in Alberta since 2010

Managing unplanned outages

The reliability of the BPS can be impacted by unplanned outages, which can be caused by extreme weather conditions and create reliability issues if the power system isn’t flexible. Operators need to adjust quickly by redispatching other generators or by using operating reserves. Without adequate resources, the system may struggle to respond to unplanned outages, leading to potential reliability issues. Also, if there are no alternative transmission lines, or if the existing ones are congested, it can be even more challenging.

Recent extreme weather events surfaced these challenges across Canada. For example, in January 2024, Alberta narrowly avoided a rolling blackout during a severe cold weather event that also restricted electricity imports^Footnote 7. With transmission lines from neighboring provinces congested and limited operating reserves available, the Alberta Electricity System Operator (AESO) took measures to maintain power supply, including asking residents to reduce their electricity usage^Footnote 8. Later, in March 2025, a major ice storm left over a million customers without power in Ontario, with some outages lasting over a week due to extensive damage to transmission and distribution infrastructure^Footnote 9. The widespread damage limited available transmission alternatives and overwhelmed system operators’ ability to redispatch resources.

How will future trends affect reliability?

Electricity demand is expected to increase significantly in the coming years^Footnote 10. Trends driving increased demand include electricity’s projected role in decarbonization efforts, with growing electrification of end-uses (like increased electric vehicle use and heat pump adoption).^Footnote 11 Further, new areas of demand growth, like data centers (ex. used to power AI) could also lead to increased growth in electricity demand.

Meeting this rising electricity demand could be a reliability challenge^Footnote 12. Higher electricity consumption could make it difficult for grid operators to reliably provide sufficient power during peak periods.

To meet increased demand while keeping costs and emissions from electricity generation low, additional supply from clean energy sources is widely expected across energy forecasts. Even in scenarios that reflect current policies, many reports project substantial growth in variable renewable energy sources (VRES) like wind and solar, primarily due to their competitive costs.^Footnote 13 Net-zero scenarios naturally show even greater VRES deployment. However, due to their intermittency, VRES must be managed carefully to maintain grid reliability.

Weather conditions also affect consumer electricity demand patterns. During extreme weather events, like heat waves or cold snaps, demand sometimes peaks while VRES output drops, leading to supply shortfalls^Footnote 14. On the other hand, when weather conditions are ideal for VRES generation, output may be high while demand is low, resulting in supply surplus^Footnote 15. This variability poses a challenge for the grid because, unlike conventional generators, solar and wind technologies lack the ability to adjust their output and are not easily dispatchable.

Ways to improve reliability

To ensure a reliable grid, the power system must continuously and safely operate during equipment outages, supply shortfalls, or surpluses. This requires a flexible grid, having the right mix of supply and transmission assets capable of responding to sudden changes in demand or unplanned outages.

One example of how grid reliability can be maintained is supply diversification by integrating VRES with dispatchable technologies such as battery storage and conventional power plants. Battery storage can store excess power during periods of surplus and provide power when needed, while other dispatchable technologies can provide base load capacity to complement VRES^Footnote 16.

Increasing transmission capacity through new transmission lines or non-wire solutions (such as dynamic line rating) can facilitate power transfer from areas with surplus to those experiencing shortfalls. Demand management solutions, like enhanced demand response and the adoption of more energy-efficient devices, can also alleviate grid load.

Widespread grid modernization efforts could help improve reliability. This may include proposing new market structures, integrating new technologies like more accurate forecasting, advanced smart metering, grid automation and Internet of Things (IoT) technology, and energy storage systems^{Footnote 17Footnote 18}.

However, as grid modernization helps improve reliability, new vulnerabilities are also being introduced. These vulnerabilities involve physical and cyber threats and can be seen in smart grids, IoT sensors, and automated systems. To maintain reliability, modernized grids require safeguarding to manage and mitigate these new risks.

Footnotes

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Following a record setting year in 2023^Footnote 1, Canadian natural gas production hit new highs in 2024, averaging 18.3 billion cubic feet per day (Bcf/d), continuing the steady growth seen since 2020. Production has been robust from January to May 2025, averaging 19.2 Bcf/d.

• Provincial contributions: Alberta (AB) remained the top-producing province, accounting for about 59.7 per cent of Canada’s natural gas output in 2024. British Columbia (BC) followed with 38.6 per cent, while Saskatchewan (SK) contributed 1.6 per cent. The rest of Canada produced 0.1 per cent. BC’s share of total Canadian production has grown since the shale/tight gas revolution in the mid 2000’s, where it was just 17.0 per cent in 2008.
• Growth drivers: In 2024, BC saw the largest year-over-year provincial increase in both percentage and absolute terms (+6.1 per cent, 0.4 Bcf/d), driven by Montney Formation tight gas development. AB’s output increased slightly (+0.6 per cent, 0.06 Bcf/d) but remained consistently high. SK production fell by 4.8 per cent after modest growth (0,5 per cent) in 2023.
• Early 2025: Canadian production was 19.2 Bcf/d in the first five months of 2025. Provincial shares stayed close to 2024 levels: AB – 59.4 per cent, BC – 38.9 per cent, SK – 1.5 per cent, and the rest of Canada – 0.2 per cent.
• Market context: Natural gas production continued to rise in 2024 and during the first five months of 2025, despite persistently low North American gas prices. The supply of liquids-rich natural gas supported the economics of Canadian natural gas production, while expanded pipelines and upcoming LNG export capacity further supported record volumes.
• Production trends: Production growth has been driven by expanded development in the Montney Formation in northeastern BC and northwestern AB. Advances in horizontal drilling and hydraulic fracturing have helped sustain high output.
• Launch of LNG Canada: In June 2025, LNG Canada began its first liquefied natural gas (LNG) exports. The project will likely source gas from its partners’ resources in the Western Canadian Sedimentary Basin, as well as from the broader western Canadian gas market.

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Hydrogen Projects in Canada

With the focus on reducing greenhouse gas emissions, hydrogen is emerging as a potential key player in Canada’s energy landscape. Canada currently produces around 4 million tonnes^Footnote 1 per annum (Mtpa) of hydrogen, with significant contributions from Alberta, which accounted for 2.6 Mtpa in 2024, including 0.5 Mtpa paired with Carbon Capture and Sequestration (CCS).^Footnote 2 A further 5 Mtpa of clean hydrogen^{Footnote 3Footnote 4Footnote 5} projects have been announced or are under development across the country.^Footnote 6 Infrastructure for transporting and storing hydrogen is also expanding to meet growing demand, though current global infrastructure remains lacking.^Footnote 7

The Progress Report for Hydrogen Strategy for Canada^Footnote 8 by Natural Resources Canada describes various modelling efforts in Canada, in which most scenarios see hydrogen accounting for between 3% and 12% of Canada’s energy demand by 2050. Scenarios with high hydrogen support or cost reductions see this share reach as high as 18%.

Hydrogen Production Methods

Hydrogen can be produced in many ways, commonly categorized by emissions intensity. These ways include: coal or biomass gasification^Footnote 9, the latter of which can be paired with CCS; Steam Methane Reformation (SMR) or Autothermal Reformation (ATR)^Footnote 10, which can both be paired with CCS^Footnote 11; methane pyrolysis; and electrolysis^{Footnote 12Footnote 13}. Hydrogen can also occur naturally, and there is ongoing research and exploration to better understand this resource.^{Footnote 14Footnote 15}

Figure 1: Summary map: Hydrogen developments in Canada since 2020—production, end-use, hubs, and strategies

Applications and Future Projects

Hydrogen is an energy carrier^Footnote 16 with many applications and a wide range of production methods. Currently, most of the hydrogen produced today is used in crude oil refining, steel making, and the chemical industry,^Footnote 17 but other potential uses include as a fuel or as a method for storing energy from renewable sources. The world uses more than 97 million tonnes^Footnote 18 of hydrogen annually, 99.6% of which is produced from fossil fuels, typically without using CCS.^Footnote 19

Plans for decarbonizing multiple industries internationally and within Canada depend increasingly on hydrogen. As shown in Figure 1, many projects are underway to leverage clean hydrogen in end-use applications like trucking and heavy industry, as well as production facilities for hydrogen via electrolysis, SMR/ATR, and biomass gasification. The future of clean hydrogen in Canada is especially promising in addressing hard-to-abate sectors, including heavy transportation, high-temperature industrial processes, and in fertilizer production,^Footnote 20 where hydrogen is synthesized to ammonia—a common feedstock for fertilizer production.

Federal financial support for hydrogen projects is currently available through the Clean Hydrogen and Renewable Energy Investment Tax Credits, the Clean Fuels Fund, the Canada Growth Fund, and the Canada Infrastructure Bank, while provincial and territorial support mechanisms vary per region. The Progress Report for the Hydrogen Strategy of Canada^Footnote 21 highlights the developments in both codes and standards and the establishment of hydrogen hubs across the country, allowing for specialized infrastructure to aid in developing the hydrogen industry in Canada.

Footnotes

1. Energy Fact Book, NRCan, page 100
2. Emerging Resources – Hydrogen, AER
3. EU unveils methodology to calculate emissions savings in low-carbon fuels, White & Case
4. Clean Hydrogen Investment Tax Credit (ITC), Government of Canada
5. Hydrogen Production and Distribution, Alternative Fuels Data Center, US DOE
6. Hydrogen Strategy for Canada: Progress Report, 1.1 Status of the Canadian hydrogen industry, NRCan
7. Global Hydrogen Review 2024, IEA, Page 106
8. Hydrogen Strategy for Canada: Progress Report, NRCan
9. Towards hydrogen definitions based on their emissions intensity, IEA
10. SMR or ATR without the use of CCS is commonly referred to as grey hydrogen. However, as terminology usage can vary widely, it can be clearer to refer to the emissions intensity of the hydrogen production pathway.
11. SMR or ATR paired with CCS is commonly referred to as blue hydrogen. However, as terminology usage can vary widely, it can be clearer to refer to the emissions intensity of the hydrogen production pathway.
12. Global Hydrogen Review 2024, IEA, Page 66
13. With hydrogen from electrolysis, the emissions intensity of the electricity used is linked with the emissions intensity of the hydrogen. For example, hydrogen derived from electricity produced by burning coal would not be low carbon hydrogen, but hydrogen derived from electricity produced from wind or solar would be much lower in emissions intensity. Hydrogen made with electricity from renewables is commonly referred to as green hydrogen. However, as terminology usage can vary widely, it can be clearer to refer to the emissions intensity of the hydrogen production pathway.
14. Global Hydrogen Review 2024, IEA, Page 94
15. Hydrogen Wildcatters Are Betting Big on Kansas to Strike It Rich, BNN Bloomberg
16. Hydrogen Explained, EIA
17. Global Hydrogen Review 2024, page 21, IEA
18. Global Hydrogen Review 2024, page 21, IEA
19. Hydrogen Guide, Wood Mackenzie
20. Hydrogen Strategy for Canada: Progress Report, 2.4 Modelling projections of low-carbon hydrogen’s role in net-zero by 2050, NRCan
21. Hydrogen Strategy for Canada: Progress Report, 1.2 Major policy and regulatory updates, NRCan

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The Trans Mountain Expansion Project (TMEP) came online in May 2024, nearly tripling the capacity of the Trans Mountain System to a total of 890 thousand barrels per day (Mb/d). This increased total western Canadian crude oil export pipeline capacity by 13 per cent and export capacity to tidewater in western Canada by about 700 per cent.^Footnote 1 Since TMEP’s first month of ramping up, the expanded Trans Mountain System has averaged 82 per cent utilization. More broadly, constraints have eased on all of Canada’s largest export pipelines over this period and Canadian crude oil prices have improved relative to international benchmarks.

Figure 1: Monthly throughput and available capacity on the Trans Mountain System

Utilization of the Trans Mountain System since the TMEP Began Service

The Trans Mountain System has been more than 75 per cent full every month since TMEP came online, except for the ramp up period in May 2024.^Footnote 2 From June 2024 to June 2025^Footnote 3, the Trans Mountain System averaged 82 per cent utilization, ranging from a low of 76 per cent in December 2024 to a high of 89 per cent in March 2025.

Since TMEP entered service, approximately 80 per cent of the Trans Mountain System’s capacity (707.5 Mb/d) is now reserved for committed shippers with long term take-or-pay contracts and the remainder (approximately 182.5 Mb/d) is made available on a monthly basis for uncommitted (also known as spot) shippers. From June 2024 to June 2025, committed capacity was effectively fully utilized each month, averaging 99 per cent utilization.

Compared to pre-TMEP levels, the Westridge delivery point^Footnote 4—at Trans Mountain’s marine terminal located in the Port of Vancouver—has seen the largest increase in throughputs, which is driven primarily by heavy oil exports (and some light oil exports) (Figure 1). These volumes are being exported by marine vessel to the U.S. West Coast and Asia. An average of 23 vessels per month departed from Westridge marine terminal between June 2024 and July 2025.^Footnote 5 Since the startup of TMEP, Canadian crude oil exports to countries other than the U.S. have more than tripled.^Footnote 6

Light crude oil and refined petroleum products also continue to be delivered to the Burnaby delivery point to serve Parkland’s Burnaby Refinery,^Footnote 7 Suncor’s Burrard Products Terminal, and surrounding areas. Additionally, the Sumas delivery point, which connects with the downstream Puget Sound Pipeline for deliveries of crude oil to Washington State refineries, has continued to be at capacity.

The Trans Mountain pipeline historically transported mostly light oil, but heavy oil has increased to approximately match light oil volumes since the TMEP came online.

Easing capacity constraints on export pipelines

In the months leading up to the completion of the TMEP, all major oil pipelines out of western Canada were running at or near capacity, as Canadian oil production increased to record levels. Shipper requests (or nominations) to use export pipelines significantly exceeded capacity, resulting in a large rise in apportionment on the largest western Canadian oil pipelines (Trans Mountain, Enbridge Mainline and Keystone) in late 2023 and early 2024.^Footnote 8

Since the startup of the TMEP, with Canadian oil production at new highs, there has been no apportionment on the Trans Mountain System. On the Enbridge Mainline and Keystone, apportionment has fallen significantly while their total utilization remained at or near capacity. Overall, oil export pipeline capacity from western Canada continues to be highly utilized (Figure 2). Additionally, since TMEP entered service, Canada’s crude-by-rail exports^Footnote 9 have fallen to annual-average levels not seen in over a decade.^Footnote 10

Figure 2: Crude oil volumes transported from western Canada relative to available pipeline capacity

WCS price differential narrowed after the TMEP entered service
In the months leading up to the startup of the TMEP, the price differential between Western Canadian Select (WCS) and West Texas Intermediate (WTI) had widened to an average of about US$18.70 per barrel in the period of September 2023 to April 2024.Footnote 11 After the startup of TMEP, with total pipeline capacity no longer being constrained out of western Canada, the differential narrowed to an average of US$12.00 per barrel over the period of June 2024 to July 2025.

This means western Canadian oil has been worth more than if the differential had remained wider, like it was in the period leading up to the expansion. A US$12.00 per barrel differential is more in-line with historical levels seen in periods when markets did not face constrained pipeline capacity.

Figure 3: WTI-WCS monthly average price differential

Footnotes:

1. Pre-TMEP, Trans Mountain set aside 79 Mb/d of capacity for service to its Westridge Marine Terminal (54 Mb/d for committed and 25 Mb/d for uncommitted service) (Source: CER REGDOCS, A3E7A3, C27827-1). Post-TMEP, the Westridge Marine Terminal can export up to 630 Mb/d of western Canadian crude (Source: Trans Mountain, Westridge Marine Terminal). Actual monthly throughputs may exceed the set-aside capacities.
2. In May 2024, system utilization averaged 55 per cent while Trans Mountain ramped up shipments on the new capacity.
3. This 13-month period excludes the ramp-up period during the first month of TMEP operations and includes the latest available throughput data at the time of publication (which Trans Mountain filed with the CER in August 2025).
4. See the Trans Mountain Pipeline Profile for a map of the delivery point locations.
5. Trans Mountain, Shipper Services. At the time of publication, datapoints for June 2024 and July 2024 were removed from the Trans Mountain webpage as it only shows the 12 most recent months. Prior to the update, the webpage showed vessel departures for those two months were 21 and 22, respectively. Vessel departures for August 2024 were 23.
6. See the Commodity Tracking System report for Crude Oil – Summary Export by Destination. Data includes all exports from Canada, not just from Port of Vancouver. Note that crude oil delivered to “other” destinations are primarily non-U.S. destinations but also includes some volumes that are held in storage in the U.S. before reaching a final destination as well as some volumes that are in-transit in the Pacific Area Lightering zone.
7. Burnaby Refinery is currently owned by Parkland Corporation. However, Parkland Corporation and its assets are being bought by Sunoco LP (Parkland News Release).
8. See the Trans Mountain, Enbridge Mainline and Keystone Pipeline Profiles for visualizations of monthly apportionment. To access the raw dataset, visit the Open Government Pipeline Throughput and Capacity Data.
9. See the CER’s Canadian Crude Oil Exports by Rail – Monthly Data webpage to access the data.
10. Rail is typically used when pipeline infrastructure is not available, or when price differentials are wide enough for rail to be economic. The differential that is required to justify shipping crude by rail varies by shipper. While the use of rail has declined recently, it is still integral to serving regions without pipelines.
11. WCS is typically discounted relative to WTI because WCS is a heavier crude oil that costs more to refine than WTI light oil, and because of the cost to ship WCS from western Canada to Cushing, Oklahoma, where WTI is commonly bought and sold.

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The installed capacity of energy storage larger than 1 MW—and connected to the grid—in Canada may increase from 552 MW at the end of 2024 to 1,149 MW in 2030, based solely on 12 projects currently under construction^Footnote 1. There are an additional 27 projects with regulatory approval proposed to come online by 2030, which—if all were to be built—could further boost Canada’s energy storage capacity to 2,768 MW. For comparison, Alberta’s all-time hourly peak electricity demand was 12,384 MW^Footnote 2 during a 2024 January cold snap.

The first energy storage project in Canada, the Sir Adam Beck Pump Generating Station, came online in 1957. However, the next project did not come online until 2013. There are three main types of energy storage currently commercially available in Canada:

1. Pumped Storage Hydropower (PSH)
2. Compressed Air Energy Storage (CAES)
3. Battery Energy Storage Systems (BESS)

Storage is playing an increasingly important role in the electricity system by improving grid reliability and power quality, and by complementing variable renewable energy sources (VRES) like wind and solar. This is predominantly by recharging during periods of low demand, then discharging when demand is high—which can also correlate with cost fluctuations. Electricity demand is projected to increase over the next five years worldwide^Footnote 3, with VRES projected to continue growing too,^Footnote 4 indicating that energy storage’s role may keep increasing in the future.

Figure 1: Map of Canadian Pumped Storage Hydropower, Compressed Air Energy Storage, and Battery Energy Storage Systems Projects – Installed, Under Construction, and Proposed for 2030

BESS is the fastest growing energy storage technology in Canada and is also the dominant storage technology in terms of capacity and number of sites. All but four projects proposed to be commissioned by 2030 are battery storage, with two CAES and two PHS projects also proposed. BESS projects generally have smaller footprints^Footnote 5 (when compared to PSH and CAES) and they have the ability to scale up in size.^Footnote 6

The storage of electricity, either directly in batteries or indirectly in other forms like compressed air or pumped storage hydro, can help balance electricity supply and demand. It allows electricity to be stored during periods of high production, low costs or low use, and then be used when other production is low, or use is high. Storage allows for a higher value-added use of existing generation and grid assets and provides the key service of complementing VRES like wind and solar in today’s rapidly changing grid.

Pumped Storage Hydropower

Canada’s only active Pumped Storage Hydropower (PSH) facility is the Ontario Power Generation’s 174 MW Sir Adam Beck Pump Generating Station.^Footnote 7 PSH facilities use gravitational potential energy by pumping water into a reservoir at higher elevation during low-demand periods and releasing it through turbines during high-demand periods to generate electricity.

Energy can be stored in the form of potential energy in large quantities of water for longer periods of time than other storage methods. However, facilities require sizeable portions of specific geology with large elevation differences, which can limit the viability of PSH facility locations. As of June 2025, PSH is the earliest and largest form of energy storage in Canada.^Footnote 8

Compressed Air Energy Storage

In Compressed Air Energy Storage (CAES), air is compressed and stored in underground structures like mines, aquifers, salt caverns or old oil reservoirs, or in aboveground pressure vessels. When electricity is needed, the air is released to power a turbine and generate electricity. There are two types of CAES: conventional compressed air energy storage (C-CAES) and adiabatic compressed air energy storage (A-CAES). When air is compressed, heat is produced. In C-CAES, the heat generated during the compression phase is released into the atmosphere. During the discharge phase, the compressed air is reheated by burning fuel, typically natural gas. The reheated compressed air drives a turbine, which is connected to an electricity generator. In A-CAES, the heat from the compression phase is captured and stored. This stored heat is then used to reheat the air before it enters the turbine where no additional fuel combustion is required.^Footnote 9 As of June 2025, the Goderich A-CAES Facility in Goderich, Ontario is the only CAES project in Canada, able to store 1.75 MW.^Footnote 10

Battery Energy Storage Systems

Battery Energy Storage Systems (BESS) are tools that store electrical energy. Within Canada, all energy storage projects currently under construction are BESS. Proposed and under-construction projects have a power range between 1 MW and 411 MW, with an average storage capacity range of 0.5 hours to 6 hours. There are different types of batteries used for large-scale energy storage, such as lithium-ion, lead acid, redox-flow, and molten salt.^Footnote 11 Among these, lithium-ion batteries are the most commonly installed for new projects.^Footnote 12 Challenges with batteries may vary with the type, such as cost or charging and discharging capacities.

Government funding for energy storage projects is increasing. The Smart Renewables and Electrification Pathways program (SREPs)—which supports clean electricity projects—recently announced $500 million in additional funding and a new round of intakes for the Utility Support Stream.^Footnote 13 This stream of the SREP program is meant to support utilities and system operators in modernizing their systems and integrating renewables while maintaining reliability and affordability.

Footnotes

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