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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Production increased by 5.3 Bcf/d compared with 2024, according to the EIA’s latest Natural Gas Monthly. Three regions — Appalachia, Permian and Haynesville — accounted for 67 per cent of total U.S. marketed gas production and 81 per cent of the growth last year.

Higher natural gas prices helped support drilling activity. The Henry Hub benchmark price rose about 60 per cent in 2025 to US$3.52 per million British thermal units (MMBtu), improving the economics of production across multiple basins.

The Appalachian Basin in the northeastern United States remained the country’s largest natural gas producing region, accounting for 36.6 Bcf/d, or roughly 31 per cent of total U.S. marketed production.

Production growth there has slowed in recent years because of limited pipeline capacity to move gas to markets. However, additional capacity began coming online in 2024 when the Mountain Valley Pipeline was authorized to start operating. Combined with higher gas prices, that helped push Appalachian production up by 1.1 Bcf/d in 2025, compared with only modest growth in 2024.

The Permian Basin in Texas and New Mexico continued to play a major role in U.S. gas growth. Production in the region rose 11 per cent, or 2.7 Bcf/d, reaching an average of 27.7 Bcf/d in 2025.

Much of the natural gas produced in the Permian is associated gas, meaning it is generated as a by-product of oil production. Even though benchmark West Texas Intermediate crude prices declined from US$77 per barrel in 2024 to about US$65 in 2025, prices remained high enough to support oil-directed drilling.

Industry surveys suggest the basin remains economically viable at those levels, with breakeven prices estimated around US$61 per barrel in the Midland Basin and US$62 in the Delaware Basin.

Another factor contributing to higher gas production in the Permian is the region’s rising gas-to-oil ratio, meaning wells are producing more natural gas relative to oil over time.

The Haynesville shale, which spans Louisiana and Texas, also contributed to production growth. Output there averaged 14.9 Bcf/d in 2025, about four per cent higher than in 2024.

Haynesville wells are typically much deeper — between 10,500 and 13,500 feet — than wells in the Appalachian Basin, which generally range from 4,000 to 8,500 feet. The greater depth increases drilling costs, but the basin’s location provides an important advantage.

Haynesville sits close to liquefied natural gas export terminals and large industrial natural gas consumers along the U.S. Gulf Coast, making it an attractive supply source for both domestic and export markets.

The EIA expects U.S. natural gas production to continue growing in the coming years as additional infrastructure and export demand support drilling activity. Expansion of LNG export capacity along the Gulf Coast is expected to play a key role in shaping future natural gas markets.

The United States has been the world’s largest producer of natural gas for more than a decade, largely because of the expansion of shale gas production since the mid-2000s.

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Colossal fossil Shell and industrial conglomerate Mitsubishi are trying to sell off their shares in the $40-billion LNG Canada liquefied natural gas megaproject, reinforcing predictions that 2026 would be the year that an oversupplied global market for the climate-polluting gas begins to hit home.

“The moves come as owners of the massive liquefied natural gas facility weigh a potential expansion, and after another stakeholder, Petronas, successfully offloaded a piece of the project,” Reuters revealed Friday, in an exclusive report citing three sources familiar with discussions.

The news agency says Shell has been working with investment bankers at Rothschild & Co. to offload up to three-quarters of its 40% share in the project, for an asking price of about US$15 billion. “Shell has expressed willingness, however, to consider different options relating to its exposure to the project’s Phase 1, which is operational, and the proposed Phase 2, given their different risks,” Reuters writes.

Mitsubishi hasn’t begun courting buyers, but has hired RBC Capital Markets while it assesses its options.

LNG Canada, the first North American facility of its kind with direct access to the Pacific Ocean, “has a supply cost advantage because prices for Canadian natural gas consistently trade at a discount” compared to the U.S. price benchmark, named for the Henry Hub pipeline distribution centre in Louisiana, Reuters explains. “Even so, existing and potential owners will consider industry fears of global oversupply of the supercooled fuel, as new LNG output comes online.”

The news comes just a month after Energy Transfer LP “indefinitely paused” its Lake Charles LNG project in Louisiana after extending its target date to start exports from 2025 to 2031, preferring instead to focus on domestic natural gas pipelines. And that wasn’t the only retrenchment, as fossil companies absorb the prospect that the LNG glut will become a “sinkhole”.

“Solar, wind power, and batteries are set to make life a misery for the liquefied natural gas market,” warned Thomson Reuters editor and news analyst Antony Currie, in one of the news agency’s prediction pieces for 2026. “Some fossil fuel executives already think the push by incumbents like ExxonMobil, Shell, and Woodside Energy to hike global production by some 50% by 2030, per the International Energy Agency, is creating a bubble. But renewable energy’s advantages will make the pop even worse.”

Public musings about that bubble have been intensifying at least since late August, when Prime Minister Mark Carney and Energy and Natural Resources Minister Tim Hodgson travelled to Germany to pledge a first wave of Canadian LNG deliveries. “I think you’re probably talking about five to seven years,” Hodgson told Politico EU in an interview in Berlin.

At the time, multiple analysts contacted by The Energy Mix and Berlin-based Clean Energy Wire said they saw limited prospects for increased LNG trade.

“There is absolutely no window in the next 25 years when you can think, oh, the EU will really need that LNG then,” wrote Adrian Hiel, Brussels-based director of the Electrification Alliance. “It’s nothing but one effort after another to push expensive, inefficient gas out of the EU’s energy system.”

Hiel predicted an “enormous glut” of LNG between 2026 and 2030, as new U.S. supply enters the global market.

Toward the end of the year, as well, industry and trade media began reporting mounting evidence of declining imports to Asia, long seen and often over-hyped as the most promising source of steady demand for Canadian LNG.

On LinkedIn, Richard Brooks, climate finance lead at Stand.earth, hailed the Shell/Mitsubishi story as big news.

“This may be a sign that this project is not performing as well financially as expected, particularly in the face of a widely reported multi-year LNG supply glut that is under way. Long-term outlook is nosediving. Projects are being cancelled and delayed everywhere, even in the USA,” he wrote.

“It means the Phase 2 expansion, which has been referred to the Major Projects Office for fast-tracking, is delayed or dead,” Brooks added.

Reuters says LNG Canada referred questions about the sale to Shell and Mitsubishi. Shell declined comment, while Mitsubishi wasn’t reachable outside business hours in Japan. Rothschild didn’t respond to a request for comment.

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By Mitchell Beer

After adopting a series of rolling deadlines to phase out Russian gas imports by 2027, the European Union still won’t need new supplies—from Canada or anywhere else—to make up the difference, energy analysts say.

On Wednesday, the European Parliament voted to phase out imports of Russian liquefied natural gas (LNG) by the end of next year and pipeline gas by September, 2027, Reuters reported. The European Commission will also propose measures early next year to phase out Russian oil purchases.

Russia was once the continent’s biggest supplier of gas, the news agency writes. But since Vladimir Putin launched his invasion of Ukraine in 2022, his country has seen its market share in Europe fall from 45 per cent to 12 per cent.

One analyst put the value of those remaining cargos at €25 to €30 million each, with more than 200 tankers filled with Russian Arctic gas landing at European ports this year.

Over the past several months, the Canadian government has pushed hard to encourage LNG exports to Europe, with Energy and Natural Resources Minister Tim Hodgson maintaining in August that a first shipment might be possible in “as little as five years”. But analysts say Europe will have no need for new gas, even with Russia falling out of the supply mix.

“The big fear is always this question of how to find alternative supply,” said Sebastian Rötters, sanctions campaigner with Urgevald, a climate finance non-profit based in Sassenberg, Germany. But “from 2027 onwards, there will be an oversupply in the market, and this is something we can already start to see.”

With multiple experts predicting a gas glut, “I don’t really think the EU will replace these volumes, and I hope they won’t replace them with long-term contracts,” he told The Energy Mix. “If we see the need for alternative supply, but at the same we don’t want to throw our climate goals out the window, it’s difficult to sign a 20-year contract.”

In a market assessment released last March, the Ember energy policy think tank said Europe will see a 54 per cent increase in LNG import capacity between 2023 and 2030, even though the continent’s gas grid operators only foresee a 4 per cent increase in demand. That disconnect will lead to more than 100 billion cubic metres of “costly supply capacity potentially being unneeded and underutilized,” the report stated. “This scale of overinvestment is equal to the combined annual gas demand of Germany, France, and Poland.”

Throughout 2024, those gas supplies also drove up gas prices by 59 per cent, Ember added, leading to higher electricity costs for consumers.

Ana Maria Jaller-Makarewicz, lead energy analyst, Europe at the Institute for Energy Economics and Financial Analysis, said Russia supplied 16 per cent of the continent’s LNG and 13 per cent of its combined LNG and pipeline gas in the first half of 2025, even after the EU decreased its gas dependence by 20 per cent between 2021 and 2023.

But “if the EU continues with policies to reduce gas consumption and scale up renewables, the bloc could replace this supply without increasing gas imports from any source.,” Jaller-Makarewicz said.

Rötters said the real issue is whether EU members—including countries like Hungary and Slovakia that are more closely aligned with the Putin regime—would want to take those steps.

“Could we offset this? Of course we could,” he said. But “in Europe at the moment, renewable energy deployment and climate-related work are not really the number one priority. So of course energy efficiency is a priority, in the sense that the EU wants to be less dependent, but we could do a lot more if the political will were there.”

Beyond geopolitics, Rötters explained that Hungary and Slovakia worked to slow down the EU ban to protect their access to relatively inexpensive pipeline gas from Europe. That led countries to negotiate a phaseout in four stages: short-term LNG contracts in April, 2026, followed by short-term pipeline contracts in June and longer-term deals at the end of this year and the following September, respectively.

If the goal is to cut off financing for Putin’s war machine, one question is whether Russia will find other customers for the gas it can no longer sell to the EU.

“The market continues to be very volatile and dependent on geopolitical issues that could affect prices, supply, and demand,” Jaller-Makarewicz told The Mix. But already, “Russia has been selling gas and LNG at discounted prices to attract buyers,” and “it might be difficult to find a market that will import the same amount of Russian gas as Europe did before Russia’s full-scale invasion of Ukraine. Gas demand in different regions has been declining, and countries like China have been decreasing their LNG needs.”

That means it will serve the EU’s geopolitical agenda if imports can be shut down, Rötters said.

“Would it help to cut this money off? I would say yes, it would,” he said. “We are pushing for very strong and immediate sanctions because the Russian economy is really in trouble. This is something Putin can still hide, but… the existing sanctions do hurt.”

At the same time, Urgevald is stressing the urgency of stopping the flow of gas payments from the EU to Russia, with Rötters pointing out that Ukraine “is helping the EU” by “saving Europe from defending against a Russian attack on EU territory. Because I don’t think it’s a fairy tale to say the Baltic countries are in imminent danger of Russian aggression.”

After the deal was adopted, Denmark’s minister for climate, energy and utilities, Lars Aagaard, praised the EU agreement as “a big win for us and for all of Europe. We have to put an end to the EU’s dependence on Russian gas, and banning it in the EU permanently is a major step in the right direction.”

But in a release following Wednesday’s announcement, Urgevald said the continent is moving too slowly.

“While the EU congratulates itself on phasing out Russian gas by 2027, the Kremlin is still set to receive billions in the meantime,” Rötters said in the release. “At the current pace, the EU will pay over €4 billion for Russian-linked LNG in 2026 alone. That is not a phaseout. That is financing a war,” and  “every delay weakens sanctions and strengthens the Kremlin.”

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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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According to the IEEFA, “Higher natural-gas prices in 2025 and 2026 are the result of strong export growth that persistently outpaces U.S. natural-gas production.”

“In other words, the high demand for gas exports is also pushing up the price of the gas that supplies 40 per cent of U.S. electricity.”

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By Faouzi Aloulou, Olga Popova, Jozef Lieskovsky

As U.S. crude oil and natural gas production have increased, so has the volume of production declines from existing wells. To offset the increasing declines, operators today must bring on new wells to sustain or increase production levels.

Between 2010 and 2024, hydrocarbon production from new wells in the Lower 48 states (L48) generally offset and exceeded declining production from existing wells. Because production from oil and natural gas wells declines over time as reservoir pressure decreases, new wells are required to maintain the same production level. The increasing number of horizontal wells has contributed to this trend because horizontal wells exhibit higher decline rates than vertical wells.

Crude oil production
In December 2023, L48 crude oil production averaged 11.0 million barrels per day (b/d). Production from wells that came online in 2023 or earlier fell to 6.7 million b/d in December 2024, a decline of 4.3 million b/d. Those declines were offset by the more than 15,000 new wells that were brought online in 2024—about 11,700 of which were horizontal wells. The new wells produced 4.4 million b/d of crude oil, enough to overcome declines from existing wells, bringing L48 crude oil production to 11.2 million b/d in December 2024.

Natural gas production
Between December 2023 and December 2024, natural gas production from wells that came online in 2023 or earlier fell from 115.4 billion cubic feet per day (Bcf/d) to 88.4 Bcf/d, a decline of 27.0 Bcf/d. New wells offset those declines, producing an average of 28.0 Bcf/d of natural gas in December 2024. L48 production for natural gas increased to 116.5 Bcf/d in December 2024.

Horizontal wells
In the mid-2000s, operators began to drill more horizontal wells, which allow them to recover more oil and natural gas quickly after initial production begins than from vertical wells. In December 2024, horizontal wells produced 94 per cent of oil and 92 per cent of natural gas in the L48 states. However, horizontal wells have a high initial production rate with a steep decline relative to vertical wells.

The rapid decline rates in horizontal wells are contributing to the trend described above with large numbers of new wells required to maintain or increase production levels.

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By Jordan Young

Liquefied natural gas (LNG) exporters in the United States have announced plans to more than double U.S. liquefaction capacity, adding an estimated 13.9 billion cubic feet per day (Bcf/d) between 2025 and 2029, according to our Liquefaction Capacity File and trade press reports. The United States is already the largest exporter in the world with 15.4 Bcf/d of capacity.

More broadly, LNG export capacity in North America is on track to increase from 11.4 Bcf/d at the beginning of 2024 to 28.7 Bcf/d in 2029, if projects currently under construction begin operations as planned. Exporters in Canada and Mexico have announced plans to add 2.5 Bcf/d and 0.6 Bcf/d of capacity over the same period, respectively. North American export capacity additions will total over 50% of expected global additions through 2029, according to the International Energy Agency.

United States: The planned liquefaction capacity additions will be concentrated around the U.S. Gulf Coast, already the largest hub for LNG exports in the Atlantic Basin. To supply these terminals, new pipeline projects will be built to transport natural gas from production areas. However, pipeline construction delays remain a supply risk for new terminals. Plaquemines LNG Phase 1 shipped its first cargo in December 2024. Plaquemines LNG Phase 2 and Corpus Christi Stage III began shipping cargoes earlier in 2025, but they have not yet begun commercial operation. Five additional LNG export projects in the United States have reached final investment decision (FID) and are currently under construction:

• Port Arthur LNG Phase 1 (1.6 Bcf/d)
• Rio Grande LNG (2.1 Bcf/d)
• Woodside Louisiana LNG (2.2 Bcf/d)
• Golden Pass LNG (2.1 Bcf/d)
• CP2 Phase 1 (2.0 Bcf/d)

Canada: On July 1, LNG Canada—the nation’s first LNG export terminal—shipped its first cargo from Train 1 after achieving first LNG production in late June. LNG Canada, located in British Columbia, can produce a combined 1.84 Bcf/d from two liquefaction trains (0.9 Bcf/d per train), and the facility is anticipated to reach full capacity in 2026. A proposed second phase of the project would double the export capacity to 3.68 Bcf/d and expand the facility to four trains, according to the Canada Energy Regulator (CER). The expansion is expected to come online after 2029.

Canada’s new LNG capacity will be on the west coast of North America, reducing shipping times to Asian markets by 50% compared with exports from U.S. Gulf Coast terminals, and will source feedgas from the Montney Formation in the western provinces of Alberta and British Columbia. Two other projects with a combined capacity of 0.7 Bcf/d are currently under construction in Western Canada. Woodfibre LNG, with an export capacity of 0.3 Bcf/d, is expected to start LNG exports in 2027. Cedar LNG—a floating LNG project with capacity to liquefy up to 0.4 Bcf/d—reached FID in June 2024 and is expected to begin LNG exports in 2028.

Mexico: Developers are currently constructing two LNG export projects in Mexico with a combined capacity of 0.6 Bcf/d—the Fast LNG Altamira Floating LNG (FLNG) production vessel (FLNG2), which has a capacity to liquefy up to 0.2 Bcf/d off the east coast of Mexico, and Energía Costa Azul (0.4 Bcf/d export capacity) on Mexico’s west coast. Both projects will source feedgas from sources in the United States. Mexico’s first LNG export cargo was produced aboard Fast LNG Altamira FLNG1 in August 2024, and natural gas transported on the Sur de Texas-Tuxpan natural gas pipeline supplies this project.

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By Chris Bonasia

Most environmental assessments ignore start-up flaring at LNG export facilities, but the waste gas emissions in this phase emit far more pollution than reported and threaten nearby communities, a new study concludes.

“Our real-world analysis shows that start-up flaring is among the highest-emission phases of an LNG plant’s life cycle and can last for up to two years,” Dr. Laura Minet, the study’s lead researcher and head of the Clean Air Lab at the University of Victoria, told the Canadian Association of Physicians for the Environment (CAPE).

“There is a false assumption that the commissioning phase is short, with regulators in Canada, and beyond, satisfied with relying on industry-provided flaring assumptions for environmental permitting that do not include modelling for the start-up phase.”

The LNG Canada facility in Kitimat, British Columbia—which was still under construction during the study period and so excluded from the analysis—“has been flaring in its commissioning phase for more than a full year,” Tracey Saxby, executive director of the environmental organization My Sea to Sky, said in a media release emailed to The Energy Mix.

Saxby called the overlooking of start-up flaring emissions “a glaring loophole” that has direct impacts on B.C. communities. “We’re calling on the BC government to immediately require full modelling and accounting of flaring emissions in the LNG commissioning phase, including for projects that have already been approved.”

The Narwhal has a deep dive into the health impacts of LNG expansion in Kitimat.

The recent study offers a first-of-its-kind global analysis of flaring, combining satellite observations with data from 48 LNG export terminals identified by the World Bank and the U.S. Environmental Defense Fund. Roughly half of the facilities began operations before satellite flaring data was available in 2012, so only newer plants could be analyzed for start-up conditions.

Researchers recorded flaring events under start-up and normal operating conditions and compared their observations against industry-reported datasets. They found major discrepancies: reported data underestimated flared gas volumes at two-thirds of the facilities, while others required further investigation. None of the environmental assessments the researchers reviewed quantified start-up flaring or modelled its impact on local air quality.

The start-up period is often portrayed as “a short phase with negligible air pollution emissions,” write the researchers. But the study shows that start-up can last up to two years, with high flaring activity persisting well beyond the first year. For a 30-year facility, start-up flaring could account for 1 to 16% of total lifetime flared gas.

“While these percentages may appear low, flaring emits pollutants, such as benzene, that can cause acute health effects even over short exposure periods,” the researchers write. They say the proximity of many LNG projects to residential areas make it essential to include start-up flaring in environmental assessments.

CAPE writes that start-up flaring is not “truly modelled” in environmental assessments for Canada’s LNG export facilities, including the planned Woodfibre LNG, Cedar LNG, and Ksi Lisims LNG projects.

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By Mitchell Beer

St. John’s-based Fermeuse Energy Ltd. has unveiled plans for a new $15-billion liquefied natural gas (LNG) project off the coast of Newfoundland, and the company’s CEO says the announcement would never have happened without policy changes introduced by Prime Minister Mark Carney.

“Without that, we would not be having a conversation today,” Swapan Kataria, CEO of both Fermeuse Energy and its project partner, London, UK-based Crown LNG, told The Energy Mix Tuesday.

“Prime Minister Carney has now started a momentum, started a movement, almost, to build a country,” Kataria added. “I hope he sticks to it, because there are a lot of people like us who committing to put their life and energy and money into building projects in Canada.”

The Fermeuse Energy development would include a 380-kilometre pipeline to carry gas from the Jeanne d’Arc Basin east of St. John’s to a liquefaction facility in Fermeuse, about 90 kilometres south of the city, the Globe and Mail reports.

The project will use advanced LNG technology to get at an estimated 9.7 trillion cubic feet of offshore gas, about three times the initial estimate for Nova Scotia’s Sable Island development, Fermeuse Energy said in a release. Kataria said the project will take advantage of the new Fermeuse Marine Base, a facility developed to support Newfoundland and Labrador’s offshore sector, while “evolving” it into a gas liquefaction hub.

With the site already approved as a marine supply base, Kataria said the LNG project would save 12 to 18 months of development time on environmental approvals that are already in place. So Fermeuse Energy and Crown LNG are planning on 18 to 24 months of regulatory approvals, followed by four years of construction. “Give or take, 54 to 60 months, we should be able to export if we do not get delayed with the regulatory process,” he said.

Gretchen Fitzerald, national program director at the Sierra Club of Canada Foundation (SCCF), said the federal Building Canada Act “may prompt all kinds of these types of proposals.” But “given the summer we’ve had in Atlantic Canada, leaders at all levels should be looking at renewable resources like wind, solar, and storage, not more fossil fuel projects like this one which will fuel the fires of climate change,” she told The Mix in an email.

“This represents yet another attempt by oil and gas interests to try and pitch an economically unavailable project to Newfoundlanders and Labradorians that only distracts from the need to transition rapidly to renewable energy,” added SCCF Head of Communications Conor Curtis. “There will not be the necessary demand in the [European Union] or elsewhere for projects like these to be viable, as demand will peak and start to decline this decade with a global oversupply of LNG set to happen. Like Bay du Nord, this is a lot of hype over something of limited economic substance.”

Kataria said Carney’s trip to Berlin last week, where he and Energy and Natural Resources Minister Tim Hodgson announced plans to send Canada’s first LNG shipments to Germany in “as little as five years”, showed “symbolic” support for a project like Fermeuse.

“We feel that Canada is now waking up, that they have to start building the country with pipelines, and connecting it to the world outside the United states,” he told The Mix. On top of the regulatory changes in the Building Canada Act, the new federal government’s most recent statement of intent “gives us the confidence to develop this, because it’s much easier to build a project in Fermeuse and connect it with Europe than to bring [gas] all the way from Alberta to Nova Scotia and load it on a vessel. I think both need to be done, but this is much faster to market…this one will start now.”

So far, he added, the project has assembled just enough investment capital to get it through the permitting process. “When we develop projects, there’s no point raising $15 billion and starting to pay interest on it today. The project is not creating any cash flow.” But “once we are permitted, after that the pathway is much easier, and there’s a lot of confidence in the investment community to participate.”

In the wake of Hodgson’s announcements in Berlin, independent analysts cast serious doubt on Europe’s future need for LNG. They noted the EU relied on energy efficiency and accelerated renewable energy deployment to reduce gas demand 17% between 2021 and 2024, spurred on by Vladimir Putin’s invasion of Ukraine, and that the continent is continuing to electrify its energy use.

“In the medium and long term, we’re not anticipating an increase in gas demand, certainly not in Western Europe,” Pawel Czyzak, Europe programme director at the Ember energy think tank, said in an email. The continent “is already heavily oversupplied towards 2030,” and “that oversupply will get even more severe if the questionable fossil fuel imports from the EU-U.S. trade [and tariff deal] are implemented.”

“Cutting dependency on gas from Russia or any other country can be achieved if gas consumption reduction measures continue in place,” added Ana Maria Jaller-Makarewicz, lead energy analyst, Europe with the Institute for Energy Economics and Financial Analysis. With the EU’s affordable energy action plan set to replace up to 100 billion cubic metres (more than 3,500 billion cubic feet) of gas by 2030, she added, “the bloc could satisfy demand without additional gas infrastructure or increased imports.”

Other analyses have warned of an oversupplied global market for LNG, where prices could soon begin to drop.

Kataria said that’s not the future he sees ahead.

“Every time somebody tells me that demand for gas is going to go down, every statistic shows it has already gone up,” he said. With more than 3.5 billion people in China, India, Vietnam, Indonesia, Pakistan, and Bangladesh, and projections that those countries will need a million tonnes of gas per year for every five million population, “getting LNG into the mix was primarily whether the gas is available, and whether the technology is available to build those pipelines. Markets can sustain the pricing—if you look at the next 10 or 11 years, you’ll see the project’s stability is not in question.”

That’s why “politically it was the perfect time,” he added. “Canada has a new government which is stable, and there is a huge effort going into nation-building. If I did not have confidence in Mark Carney’s vision of building the nation, we would not have initiated this project.”

Kataria said it’s too soon to say whether the project will need any form of support, but—unlike some of its counterparts in Alberta—Crown LNG has never relied on government subsidies.

“If the project cannot hold its own feet on its own ground for its commercial existence, then it doesn’t deserve to exist,” he told The Mix. It might be a different story, for example, if a 50% U.S. tariff on a large share of the project’s construction supplies drove up costs. But “starting from the ground up, we’ve never gone to any government asking for any support in 3½ years.”

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