Green hydrogen skeptics correctly observe that the sector has shifted, but they misread what that shift represents. Green hydrogen is moving from early-stage hype to disciplined execution, as capital markets and policymakers concentrate on projects with bankable fundamentals and credible buyers. That winnowing process is not evidence of collapse; it is how clean-energy sectors mature.

Pointing to the cancellation or redesign of a single wind-to-hydrogen project as proof the sector was a fad misses how large infrastructure markets evolve. Projects routinely shift as financing conditions, regulation and demand signals mature, while other proponents continue advancing through permitting, engineering and offtake negotiations. It also overlooks the policy architecture Canada and its trading partners have built to integrate renewable hydrogen into industrial decarbonization, heavy transport and export value chains.

As the sector moves from headlines to creditworthy grid-integrated projects, simplistic narratives risk misleading communities and investors.

Momentum across Canada

Across Atlantic Canada, green hydrogen projects are progressing in a more measured, credible way than early hype suggested. These initiatives are grounded in strong wind resources, proximity to export markets, and provincial strategies that explicitly tie hydrogen to industrial decarbonization and rural economic development.​

Nova Scotia’s Department of Environment and Climate Change has already approved two large‑scale green hydrogen and ammonia projects along the Strait of Canso, designed to use onshore wind power for exports to Europe.​ EverWind and Membertou are also advancing Nova Scotia’s largest wind buildout (more than 650 megawatts) and a multibillion‑dollar export complex, supported by Germany’s interest in Atlantic Canadian green ammonia. These developments signal that serious international buyers still see this region as strategically important.​

Newfoundland and Labrador has selected multiple proponents – including EverWind, Abraxas Power, Toqlukuti’k Wind and Hydrogen, and North Atlantic Refining Limited (NARL) – for multi‑phase green hydrogen and ammonia export projects, underpinned by a dedicated Hydrogen Development Action Plan that positions the province as a “clean energy centre of excellence.”​

Most recently, EverWind secured a major strategic investment of $240 million to advance its Nova Scotia wind portfolio and green fuels platform, reinforcing that capital is still flowing to credible Atlantic Canadian projects.

Quebec alone has mobilized nearly $10 billion in public and private investment over the coming decade, with major projects including TES Canada’s multibillion-dollar green hydrogen facility, Air Liquide’s 20-megawatt PEM (proton exchange membrane) electrolyzer in Bécancour, StormFisher’s Varennes e-methanol plant, and Enbridge’s 20-megawatt Gatineau project injecting hydrogen into the gas grid. The province’s hydrogen road map and “Vallée de la transition énergétique” are anchoring multiple industrial deployments in existing clean-power assets.

Elsewhere, Ontario’s Niagara Hydrogen Centre (Atura Power) will link a 20-megawatt electrolyzer to the Sir Adam Beck hydro station, while federally supported projects – such as Air Products’ net-zero hydrogen energy complex in Edmonton and AVL Fuel Cell Canada’s research and development facility in Burnaby – underscore that hydrogen development is advancing across multiple provinces under coordinated strategies.

International market signals

Globally, the sector’s trajectory is clear: low-carbon hydrogen production is up roughly 60% since 2021, installed electrolyzer capacity has grown ninefold, and investment in electrolyzers and carbon capture has expanded from about $500 million in 2021 to nearly $8 billion in 2025.

At the same time, the European Hydrogen Bank is translating policy into real demand: its first auction awarded roughly €720 million in production-linked support to projects in Spain, Portugal, Finland and Norway, while its second round was four times oversubscribed – 61 bids seeking €4.8 billion against a €1.2 billion budget – supporting plans for 6.3 gigawatts of electrolyzers and 7.3 million tonnes of renewable hydrogen over 10 years.

Moreover, in January 2026, the European Commission approved €200 million in German state aid for Canadian-produced renewable hydrogen exports to the EU: a clear demand signal for Canadian green hydrogen.

Together, these successes make clear that global hydrogen markets are not retreating; they are institutionalizing long-term demand through scaled capital deployment and binding policy frameworks, creating tangible export opportunities for credible Canadian projects.

What serious hydrogen development looks like

Yes, interest in green hydrogen has cooled since the early-2020s hype, and some capital has pulled back. But policy frameworks, climate mandates and declining technology costs continue to underpin long-term demand growth toward 2030 and beyond. To be clear: Canada’s approach is built on that multi-decade horizon – not a short boom cycle.

Green hydrogen will not succeed everywhere, nor should it. Project cancellations are a sign of market discipline, not collapse. What’s actually happening in the green hydrogen sector is a shift from hype-driven, “anywhere, at any cost” projects toward fewer, better-sited hubs that align cheap renewables, strong grids and real customers. Countries that move early in this more disciplined phase will shape future clean-energy trade. Canada has the assets to compete – if it stays the course.

David Billedeau is president and CEO of the Canadian Hydrogen Association. Derek Estabrook is executive director of the Atlantic Hydrogen Alliance. Michèle Landry is directrice générale of Hydrogène Québec.

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A quaint northerly outpost of Napa Valley wine country, Calistoga has struggled to keep the lights on when wildfires strike the region. Now it’s got a brand-new microgrid to run the whole town for days on end without any onsite fossil fuels, just batteries and liquid hydrogen.

After disastrous conflagrations in 2017 and 2018, utility Pacific Gas & Electric began preemptively shutting off power lines to avoid sparking fires amid dangerously dry, windy conditions. “We were the first community in all of PG&E’s network that was getting our power shut off to protect us,” says Calistoga City Council member Lisa Gift. ​“By 2019 we were one of the first communities to have a microgrid in all of PG&E’s network, and that was being powered by diesel generators.”

PG&E arranged a bank of truck-based diesel generators to sit in the town during fire season. When the utility cut grid power, the generators kicked on, belching smoke in a particularly beloved pocket of the 5,000-person community. “We’re a small town, so they would come up and they’d be polluting the environment, taking up our dog park – loud, gross, noisy,” Gift recalls.

Now the diesel generators are gone and the park has been turned back over to Calistoga’s canine companions.

Community microgrids are the future of the energy system.

– Craig Lewis, executive director, Clean Coalition

On a slim parcel of city land next door, publicly traded energy-storage company Energy Vault installed lithium-ion batteries and a 234-foot, reinforced-steel tank for liquid hydrogen (designed to withstand a roaring fire, should it ever come to that) that runs a bank of hydrogen fuel cells.

Altogether, this compound should be able to meet Calistoga’s electricity needs without any power from the broader grid. It’s contracted to produce up to 8.5 megawatts for 48 hours, whenever PG&E shuts off grid power because of fire concerns. Refilling the hydrogen tank could let it run for several days more.

Showcasing a speculative technology

“Even though we’re taking elements – fuel cells, batteries, liquid hydrogen storage and distribution – that have been used before in commercial settings, they’re coming together for the first time as resiliency,” says Craig Horne, Energy Vault’s senior vice president for advanced energy solutions, in an interview before the project’s unveiling in early August.

Fans of hydrogen hail it as a solution to just about any entrenched decarbonization challenge, from heavy transport to steelmaking to on-demand power. But how hydrogen is produced makes a huge difference in its climate impact; seemingly clean sources can actually rack up major carbon emissions for negligible benefit.

For now, the clean hydrogen economy remains largely speculative, with hardly any truly clean hydrogen being produced or any real projects using it. Many planned clean hydrogen projects have vanished without a trace, following a short-lived boom fuelled by Biden-era support.

In Calistoga, Energy Vault has tapped hydrogen to deal with a very specific set of constraints – delivering energy without local emissions, over multiple days, in a tight footprint – but the cleanliness of that hydrogen is a more complicated issue than public descriptions of the microgrid suggest.

A high-stakes energy solution

The key players all have a lot riding on the project.

Energy Vault, which previously raised several hundred million dollars in a singular bid to store energy with multi-storey robotic cranes that stack blocks, wants to build a new long-duration storage business around this hydrogen microgrid showcase.

Plug Power, the financially challenged hydrogen company, points to Calistoga as its largest deployment of hydrogen fuel cells: a beefy eight megawatts, after 28 years of hard work.

And PG&E has orders from regulators to add more clean energy microgrids in communities where it regularly cuts off power. Calistoga was its first delivery on that directive, after a few years of soliciting proposals and a couple more years of permitting and construction. “Community microgrids are the future of the energy system,” says Craig Lewis, who advocates for such projects as executive director of the Clean Coalition non-profit. The Calistoga microgrid is ​“a commercial-scale experiment, and I’m grateful for it.”

The results of that experiment will take time to analyze. It could unleash a new, replicable model for premium-priced community-level backup power. Or the quirkiness of the design and the murkiness of hydrogen’s supply chain and emissions could make it a quixotic outlier of questionable climate value.

Power that’s cleaner and more compact

The Calistoga microgrid poses an answer to the question of how to provide a few days of backup power to a small town in a small space, without worrying too much about cost. The limitations drove the design, which turned out quite unlike anything built thus far. Energy Vault had to figure out how to pack 293 megawatt-hours of storage into just two-thirds of an acre. The lot used to hold debris from city works, like old bits of sidewalk and pipes, Horne says.

Lithium-ion batteries have proven themselves capable of storing power, be it as a Powerwall in someone’s garage or as a large-scale grid storage facility. But to store nearly 300 megawatt-hours, grid battery enclosures need more acreage than was available to lease from the city. Even if enough batteries could fit, the auxiliary power consumption for keeping them safely cooled would pose a challenge for a project that’s supposed to mostly sit around waiting for an emergency event.

Hydrogen gas can be liquefied by cooling it to ultra-low temperatures, which unlocks greater energy density. When converted back to gas and run through fuel cells, it produces a stream of electricity and no byproduct besides water vapour. That core technology powers hydrogen vehicles, though their cost and inconvenience make for a widely derided car-ownership experience.

At Calistoga, the hydrogen flows directly to six Plug Power GenSure 1540 fuel cells, boxy containers with cooling units stacked on top, making them about two storeys tall.

The engineers added a small lithium-ion battery (7.7 MW/11.6 MWh) to perform ​“black start,” the complicated and crucial task of rebooting an electrical system after a complete blackout, Horne notes. The battery also buffers the output of the system while the hydrogen gets up and running. Then the power flows to Calistoga’s grid, which, when PG&E shuts off the transmission lines, will be fully islanded from the surrounding network.

The hydrogen is stored onsite in an 80,000-gallon tank, manufactured in Minnesota by Chart Industries. The tank holds enough to power the fuel cells for about two days, but Energy Vault will try its best to keep the lights on beyond the contracted timeframe, Horne says. So the company made sure the tank can be refuelled while it’s in active use. “The task is to squeeze toothpaste into a toothpaste tube that was being squeezed,” Horne says. ​“That’s what we proved in our acceptance testing, running for multiple hours while the fuel cells were running and a tank trailer here in the driveway is pushing liquid hydrogen into the tank itself.”

How clean is ‘clean hydrogen’?

The microgrid’s promise as a clean energy breakthrough, of course, hinges on the supply of clean hydrogen, but supply chains are barely getting started. Almost all commercial hydrogen is currently made from methane gas, a fossil fuel, through a procedure called steam methane reforming that sends the carbon dioxide byproduct straight into the atmosphere.

For hydrogen to stake any claim as a climate solution, it needs to be made without massive carbon emissions. That usually involves an alternative production method called electrolysis, which separates hydrogen from water using electricity. But this method can produce even more emissions than the dirty methane version if the electrolyzers are drawing power from the grid rather than dedicated renewable sources like solar and wind.

Energy Vault describes the hydrogen it’s using in Calistoga as ​“clean,” which Horne clarified as meeting the federal standard of no more than four kilograms of carbon dioxide emitted per kilogram of hydrogen produced. But he declined to name the source. Notably, California has subsidized hydrogen fuelling stations for more than a decade but still hasn’t managed to develop a clean hydrogen supply in-state. So for Calistoga’s hydrogen to be clean, it must be coming from somewhere else.

We can do more and waste less, and so that’s how we can be more cost effective.

– Craig Horne, senior vice president for advanced energy solutions, Energy Vault

During a tour of the microgrid, Deepesh Goyal, vice president of stationary power at Plug Power, told Canary Media that Plug Power currently supplies hydrogen from its electrolyzer site in Georgia, which runs on grid power. More than half of Georgia’s electricity comes from fossil fuels, so that electrolysis incurs substantial power-plant emissions. Plug Power buys credits for clean energy supply to compensate for this, Goyal says.

To meet the highest federal standard for clean hydrogen, producers need to obtain clean power matched to their consumption on an hourly basis in the areas where they operate. Plug Power did not respond in time for publication to questions clarifying what type of credits it buys. But a spokesperson for Energy Vault told Canary Media that currently there aren’t any facilities that could supply Calistoga with liquid hydrogen from electrolysis powered by time-matched, dedicated clean electricity, and the earliest such facility is targeting completion in 2026.

Goyal also says some of Calistoga’s hydrogen comes from an unnamed partner in Las Vegas that uses renewable natural gas (RNG) as its feedstock. As it happens, legacy gas supplier Air Liquide opened a steam methane reformer in that area a few years ago to serve California’s demand. Air Liquide says it can substitute RNG for the usual methane, which would make the resulting hydrogen carbon-negative according to the convoluted calculations of California’s clean-fuels bureaucracy.

It’s still hydrogen made by splitting methane and releasing carbon dioxide, but it looks good on paper thanks to controversial rules that privilege certain politically connected providers of RNG.

A climate solution that’s less than ideal

If someone were to design a climate solution from a blank slate, they probably wouldn’t run electrolyzers on grid power in Georgia in order to load the super-cooled hydrogen onto diesel-powered tankers and haul it more than 4,500 kilometres to Northern California, where it will sit around almost every day awaiting a utility power outage. “We still have to truck in that hydrogen,” Gift says. ​“That’s not ideal, but we were trucking in the diesel, and we were trucking in the diesel sometimes three times a day and burning that diesel.”

One incontrovertible fact is that the microgrid doesn’t combust anything onsite, so the operations within the fenceline emit almost no carbon emissions and don’t affect air quality. But it will be hard to gauge the real climate impacts of such a project until a more verifiably clean and geographically localized hydrogen supply chain develops.

Several companies have said they will build truly green hydrogen production in the coming years. That task has grown only more difficult with the Trump administration’s efforts to thwart renewables development and vastly curtail clean hydrogen tax credits.

Confronting the outsized costs of liquid hydrogen backup

The other make-or-break variable for hydrogen-backed resilience is how much it costs. Liquid hydrogen is an expensive, specialty fuel produced by only a handful of suppliers in the United States, and clean liquid hydrogen is even rarer.

For this first project, Energy Vault didn’t need to worry about consumer price sensitivity. The city of Calistoga isn’t paying Energy Vault for backup power: PG&E is paying the company to provide this service, out of funds socialized across the utility customer base. In fact, Calistoga is making some money, since Energy Vault leased the land from the municipality for 10 years.

The project’s total price tag has not been made public. Regulators allocated up to US$46.3 million for PG&E to spend on the endeavour. Energy Vault closed $28 million in project financing this spring to support construction. The company also said on Thursday that it has raised $300 million to launch Asset Vault, a subsidiary that will build, own and operate storage projects, with Calistoga as one of two anchor properties.

Horne allows that the hydrogen microgrid costs more than diesel generators up front, but argues that it can be competitive in terms of operating costs, given all the hassles associated with diesel. “We can do more and waste less, and so that’s how we can be more cost effective,” he says.

The regulatory authorization paints a different picture. The California Public Utilities Commission explicitly allowed PG&E to spend more money than the diesel generators cost in order to test a new model for cleaner resilience. “This project was supported by a CPUC plan that said we could build a solution that costs no more than twice what it would cost to deploy diesel generation over 10 years,” says Jeremy Donnell, a senior manager for microgrid strategy and implementation at PG&E. ​“It’s a bit of an arbitrary marker, but that’s what was laid out, and this project did come in under that threshold.”

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“But still, we have a ways to go to bring the cost down,” Donnell adds. ​“So hopefully, through implementation of this first project, Energy Vault learned a lot, the industry learned a lot on how to integrate these solutions in future projects.”

Energy Vault hopes to improve the project economics by upgrading the site to allow regular power exports to the grid.

Currently, the system is configured to push out power only when PG&E has scheduled a shutoff event; that means the microgrid sits idle almost every day of the year (and is unavailable for unforeseen outages, like if a tree falls on a key line). But with the right permissions and technical tweaks in place, Energy Vault expects to use the battery, and potentially even the hydrogen, to send power to California’s grid at particularly lucrative times.

“We can now have a viable second revenue stream outside of providing that resiliency service, without compromising our ability to provide the resiliency service,” Horne says. PG&E amended its contract this summer to clarify that Energy Vault is allowed to pursue this, provided it does not interrupt delivery of the required resilience services.

Going forward, Calistoga will serve as a showcase for Energy Vault’s new ​“H-Vault” product line, marketed as a high-tech option for long-duration clean energy needs. Hydrogen tanks will join gravity-based block stacking and conventional lithium-ion batteries as the company’s core offerings.

For the people of Calistoga, the project softens the upheavals of living through climate-change-induced extreme weather, without all the downsides of onsite fossil fuel combustion.

“Is it absolutely perfect? No,” Gift says. ​“But as a society, it is about making that next best right step. And for us in our community, this was that next best right step.”

For Energy Vault and the budding hydrogen industry, the next right step will be expanding hydrogen production that’s definitively low-emissions, and closing the 4,500-kilometre gap between supply and demand.

Julian Spector is a senior reporter at Canary Media. He reports on batteries, long-duration energy storage, low-carbon hydrogen and clean energy breakthroughs around the world.

Wendy Becktold contributed reporting from Calistoga.

The post A new California microgrid runs on hydrogen. But how clean is it? appeared first on Corporate Knights.

This is no longer the case.

Canadian pension funds have risked billions of dollars in workers’ retirement savings on gas companies that make the climate crisis worse and that face terminal decline as the energy transition accelerates. While gas companies insist they can decarbonize their operations and protect their business model by repurposing their infrastructure to transport and use hydrogen, these flimsy claims don’t stand up to due diligence.

As climate change provokes stronger emission-reduction policies and as cheaper zero-carbon technologies proliferate, gas companies are soon entering an era of shrinking demand and lost customers. This could result in billions of dollars in stranded gas assets and significant losses for Canadian pension funds.

New research published by Shift reveals the extent of these climate-related financial risks. Nine of Canada’s public pension managers are co-owners of 22 private gas distribution, transmission, power generation, processing and storage companies, collectively operating nearly 350,000 kilometres in pipelines globally.

As long-term investors with a fiduciary duty to invest in members’ best interests, pension funds are obligated to manage climate-related risks. Owning thousands of kilometres of gas pipelines has become incompatible with this duty.

– Patrick DeRochie, Senior Manager, Shift Action for Pension Wealth and Planet Health

Demand for low-cost electrification technologies, like heat pumps, renewable energy and battery storage, is skyrocketing. Gas companies face the prospect of lower demand for gas transmission and distribution – leading toward a “gas utility death spiral.” Gas utility customers are increasingly choosing to leave the gas system (for example by swapping their gas furnace for a heat pump). As more customers ditch gas, utilities must spread their fixed infrastructure costs over a shrinking pool of customers, driving up prices for those remaining. That in turn pushes even more gas customers to leave.

There’s no safety for pensions in betting that the energy transition will occur slowly. The longer these pipelines operate – perpetuating the production, transportation and combustion of methane – the worse the climate crisis gets. This, in turn, multiplies risks for pension portfolios across the wider financial system.

Banking on hydrogen puts pension managers in a bind

Gas companies downplay their exposure to this growing transition risk by touting plans to repurpose their infrastructure to transport and use hydrogen. Hydrogen may well play a niche role in the energy transition in hard-to-decarbonize industrial processes. But expert analysis has poured cold water on the potential for hydrogen’s use in existing gas infrastructure, concluding that hydrogen is “expensive to produce, difficult to transport, and a second- or third-best clean energy solution in almost all proposed markets.”

A peer-reviewed 2024 study found that “hydrogen is not an effective decarbonization tool for use in homes and buildings” and that “attempts to repurpose gas systems for use with hydrogen face major safety, technical, political, regulatory and economic hurdles.” A meta-review of 54 studies on hydrogen for home heating concluded that none supported heating with hydrogen at scale.

This should set off alarm bells for Canadian pension managers.

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The Ontario Teachers’ Pension Plan recently bought large stakes in gas distribution and transmission companies in the United Kingdom and Italy. Similarly, the British Columbia Investment Management Corporation co-owns gas pipeline networks in Brazil, Czechia, Germany and the United Kingdom. Both pension managers claimed that their gas investments were about “net-zero transition” and “decarbonization” but have neglected to disclose credible plans for how these high-carbon assets could profitably transition.

The Canadian pension sector’s significant exposure to gas companies puts these investment managers – and the pension plan members they invest on behalf of – in a bind.

As long-term investors with a fiduciary duty to invest in members’ best interests, pension funds are obligated to manage climate-related risks. Owning thousands of kilometres of gas pipelines has become incompatible with this duty.

In the long run, there are no winners when investors bet against the energy transition.

Pension managers should act quickly to ensure the climate integrity of their risky gas investments – helping to protect both financial returns and a healthy planet on which to enjoy them. This means increasing transparency and disclosure of gas company holdings and how they are aligned with pension fund net-zero commitments, halting investments in unjustifiable gas and hydrogen infrastructure, and acknowledging the need for gas companies to transform their business model and plan for the decommissioning of gas infrastructure over time.

It’s time for pension funds to stop pretending that gas is a “transition fuel” or that hydrogen will rescue their soon-to-be-stranded gas assets. If gas companies refuse to align their business with credible decarbonization plans, they don’t belong in pension portfolios.

Patrick DeRochie is the senior manager for Shift Action for Pension Wealth and Planet Health, a charitable project that tracks the fossil fuel investments and climate policies of Canadian pension funds and mobilizes beneficiaries to engage their pension managers on the climate crisis.

The post Hydrogen won’t rescue pension funds from bad bets on gas appeared first on Corporate Knights.

The bank, which folded on Friday after about a year of gradual decline, was involved in financing 62% of the country’s community solar projects, which are often meant to serve lower-income neighbourhoods, the New York Times reports. “The devastation comes at a critical moment for a nascent industry that is central to the effort to cut the greenhouse gases dangerously heating the planet,” the Times says.

“While the Biden administration took steps over the weekend to prevent the immediate failure of thousands of climate technology and clean energy companies that relied on Silicon Valley Bank, it hasn’t been able to find a buyer willing to take on SVB’s domestic lending portfolio — leaving some major companies scrambling to secure new lines of credit,” E&E News writes.

“The administration’s moves, which include backing all of SVB’s cash deposits, also have failed so far to quell broader concerns about midsize regional banks, which often are more willing to support new companies and up-and-coming industries,” E&E adds.

It was the biggest U.S. bank failure since the 2008 financial crash. Forbes contributor Mark Le Dain has an account of how the collapse took shape and what happens next, while Politico chronicles the U.S. government’s rescue effort.

The ‘climate bank’

“Silicon Valley Bank was in many ways a climate bank,” Kiran Bhatraju, CEO of Arcadia, the country’s biggest community solar manager, told the Times over the weekend. “When you have the majority of the market banking through one institution, there’s going to be a lot of collateral damage.”

And the crash came at a moment when climate tech “is one of the few bright spots in an overall tech downturn,” added Sarah Sclarsic, managing partner at climate venture capital firm Voyager. “This isn’t folks in Silicon Valley building photo sharing apps. These are folks across the whole country, in Detroit and Texas and everywhere in between, building things that matter.”

The Times talked to some of the companies affected by the crash and traced the uncertainty they face over the next several months. Forbes columnist Le Dain points to the big hole the bank’s departure leaves in the private financing driving the U.S. clean technology boom.

“SVB formed a dedicated cleantech practice approximately 15 years ago, well ahead of most of its financial peers,” he writes. “This was a signal to many cleantech entrepreneurs that this was the bank for them, and it also meant the bank typically had more experience in the sector.”

Last year, the bank committed US$5 billion to sustainability loans and investments, compared to the hundreds of millions available from larger public banks. “If you were a builder in cleantech you liked everything they were doing, but you now find yourself unable to access your funds,” Le Dain said before the federal rescue plan was announced. Now, even with those deposits secured, SVB’s demise leaves its former clients without the credit they depend on to maintain and expand their operations.

SVB “was the bank that would always pick up the phone when other large money center banks wouldn’t,” tech sector analyst Daniel Ives of Wedbush Securities told E&E News, and its failure will “put much tighter financial conditions for banks around startups.”

How many additional headwinds?

That makes the bank’s collapse “a major blow to early-stage and even late-stage tech startups looking to get financing,” he said.

“These things start to add up,” said sustainable finance analyst Daniel Firger, founder of Great Circle Capital Advisors. “How many additional headwinds can early-stage climate tech founders sail upwind against?”

Galvanize Climate Solutions co-founder Tom Steyer recalled SVB as a bank that was willing to work with northern California start-ups with neither assets nor cash flow to bring to the table. Despite those risks, “this wasn’t the part of the business that got them into trouble,” he told Bloomberg Green. “What failed is the way they ran their balance sheet.”

But several analysts told multiple news outlets that the loss will be felt keenly — and the country’s cleantech entrepreneurs aren’t out of the woods yet.

“When we talk about climate innovation, we’re often talking about cutting-edge, highly experimental, and at times risky developments,” said Amali de Alwis, CEO of Subak, a non-profit climate accelerator based in the UK. That can mean large, long-term investments in hardware and technology, she told Bloomberg.

“The question is, if it’s not SVB, who is it?”

But “if the flywheel of financing for early-stage climate innovation stops during these critical years, that’s going to be a big problem,” Firger told the Times.

Solar companies step up

While Bhatraju told Utility Dive the collapse will “have an impact on the broader industry,” he and other industry executives were already pointing to the steps they could take to stabilize their operations.

Mary Powell, CEO of rooftop solar giant Sunrun, said her company had less than $80 million on deposit with SVB, adding that she was “pleased” the federal government had made sure those funds were available. Beyond that, “Sunrun has long-standing banking relationships with a large number of financial institutions, and we remain confident in our ability to replace SVB’s undrawn commitments,” she said.

Community solar company Nautilus Solar Energy said it was unaffected by the collapse, but expressed support for “those in our industry negatively impacted,” Utility Dive says. Home solar company Sunnova said its exposure was limited to SVB being a lender to one of its warehouses.

Raymond James renewable energy research analyst Pavel Molchanov said U.S. banks have a “strong appetite” for solar and other renewable energy projects because of the “low risk involved”. That interest will ensure that other lenders step up to take SVB’s place.

“Of course other financiers will fill the gap because these are some of the best infrastructure projects in America,” Bhatraju agreed. “But [financing] pipelines will be in flux for some time as those new relationships get sorted out and due diligence processes get under way.”

Molchanov said the “more substantive issue for project developers in recent months has been the cost of capital, which of course has risen along with higher benchmark interest rates.” That means community solar companies have “plenty of cash is available, just at a higher cost.”

This article is republished from The Energy Mix. Read the original article.

The post What the collapse of Silicon Valley Bank means for climate tech appeared first on Corporate Knights.

In Canada, the federal government’s 2020 hydrogen strategy posits the fuel could supply as much as 30% of Canada’s final energy consumption by 2050. That may be wildly optimistic: the Canadian Climate Institute released a report in February 2021 that found that hydrogen could supply 3 to 10% of energy demand by 2050.

Still, several provinces have their own hydrogen strategies. And companies are looking for government assistance to help finance projects that would build out a hydrogen infrastructure, from production to consumption.

In the great debate over the global energy transition, natural gas producers and their political backers insist there is ample room in a net-zero world for “blue hydrogen,” which is made using gas. Many environmental advocates argue that government support should be provided only to “green hydrogen” that is produced using renewable electricity.

A number of governments agree. Germany – which has ruled out providing subsidies for gas-fuelled hydrogen production – signed a deal with Canada this summer to support the development and export of “green” hydrogen, which is made using renewable power such as offshore wind.

Still, fossil fuel proponents are pushing to deploy North America’s vast natural gas infrastructure to produce hydrogen for transportation, industry and even some building heating.

In Edmonton’s industrial heartland, energy companies are looking to develop blue hydrogen projects that will use natural gas as a feedstock, with plans to capture most carbon dioxide emissions from plants and sequester them underground. The bulk of hydrogen currently made in Canada (about three million tonnes in 2020) is made from natural gas without carbon capture technology, otherwise known as grey hydrogen. But that may be changing.

Allentown, Pennsylvania–based Air Products will begin construction this fall on a $1.6-billion plant that it says can capture roughly 95% of CO2 emissions and provide low-carbon hydrogen to customers in Alberta.

At the same time, Suncor Energy and ATCO, both of Calgary, are jointly pursuing a $4-billion plant near Edmonton that would produce 300,000 tonnes of hydrogen annually in its first phase, with a planned expansion to 900,000 tonnes per year.

In an interview in September, officials from Suncor and ATCO said the firms are now in advanced planning on the hydrogen project and have chosen a site at ATCO’s existing energy centre in Fort Saskatchewan. The firms hope to make a final decision to proceed early in 2024, with plant start-up by the end of 2027.

Both projects will use a new process called autothermal reforming, which claims to allow for greater capture than the traditional steam methane reforming approach. In both, much of the “low-carbon hydrogen” will be used at refineries owned by Suncor and Air Products partner Imperial Oil to reduce the carbon content of their liquid fuels.

Can blue hydrogen truly be low-carbon?

In the dispute over whether blue hydrogen can be green, some analysts suggest that hydrogen from natural gas can be a very low-carbon energy source, but those claims hinge on assumptions that are open to challenge. They argue the focus shouldn’t be on the colour but rather on the life-cycle carbon intensity of the fuel. However, natural-gas-based hydrogen is not currently carbon-competitive with green hydrogen – even with carbon capture.

The fledgling industry faces enormous challenges in making the promise of low-carbon blue hydrogen a reality.

There are two overriding factors: the amount of emissions involved in the extraction, processing and transport of the gas feedstock, and the efficiency of carbon capture at the plant together with the permanence of sequestration.

The conclusion that gas-based hydrogen can be low carbon assumes that the industry can virtually eliminate carbon dioxide and methane emission leaks from the gas system. It also would require the hydrogen producers to meet their ambitious carbon-capture targets and ensure the carbon is permanently sequestered. Considerable skepticism is warranted.

In an assessment released in September, the Institute for Energy Economics and Financial Analysis reviewed 13 large-scale carbon capture and storage (CCS) projects and found they had almost all significantly under-performed on promised emission reductions.

In an open letter to Finance Minister Chrystia Freeland earlier this year, some 400 academics from science, engineering and other disciplines urged the government to drop its planned tax credit for CCS. Instead, Freeland confirmed it in her 2022 budget.

The academics argued that CCS “is neither economically sound nor proven at scale, with a terrible track record and limited potential to deliver significant, cost-effective emissions reductions.”

Critics maintain that the expansion of gas-based hydrogen production is merely locking in our reliance on climate-warming fossil fuels and on an industry that has failed to live up to its environmental commitments.

“It’s not realistic to believe that blue hydrogen can ever be a zero-emission energy source,” says Julia Levin, national climate program manager at Environmental Defence. Where hydrogen is needed, it should be produced only from renewable electricity through the process of electrolysis, she argues.

Green hydrogen on the rise

For green hydrogen, electrolyzers are used to split water into hydrogen and oxygen. The process is significantly more expensive per tonne of hydrogen than the natural gas process – even with the high costs of CCS – but electrolyzer costs are falling rapidly.

The UN-based International Renewable Energy Agency has forecasted that by 2030 – and perhaps as early as 2028 – the hydrogen from renewable power will be cheaper than gas-derived hydrogen with carbon capture.

Countries around the world – including Australia, Egypt, Chile and India – are pursuing large-scale hydrogen plants powered by renewable energy.

On Canada’s East Coast, Nova Scotia and Newfoundland and Labrador both see significant opportunity for offshore wind to be used in hydrogen production. During an August visit, German Chancellor Olaf Scholz joined Prime Minister Justin Trudeau in Newfoundland, where they signed an agreement that commits to developing wind-generated hydrogen for export to Europe.

Where there is existing natural-gas infrastructure, provincial governments are still looking for opportunities to maintain and extend its economic value.

Sean McCoy, an assistant professor in the Department of Chemical and Petroleum Engineering at the University of Calgary, says blue hydrogen can be competitive on a carbon-intensity basis with hydrogen from renewable sources, assuming ultra-low amounts of methane leakage upstream and greater than 90% efficiency of carbon capture at the plant.

Perhaps a bigger thorn for blue hydrogen than the efficiency of CCS is the level of emissions – especially methane – that occur in the extraction, processing and transportation of natural gas. Methane is a potent greenhouse gas with a global warming potential 83 times that of CO2 over a 20-year time frame.

It’s not realistic to believe that blue hydrogen can ever be a zero-emission energy source.

-Julia Levin, national climate program manager at Environmental Defence

McCoy notes that numerous studies have shown that Canada is “chronically underestimating” the amount of methane being emitted by the oil and gas sector. He points to a 2020 study concluding that emissions could be as much as 60% higher than is being reported in Alberta and Saskatchewan. Any hydrogen project that wants to assert a low carbon intensity will have to provide compelling evidence that its gas suppliers properly track and eliminate methane emissions from their supply chains.

McCoy calculates that GHG emissions from green hydrogen would average roughly three kilograms of CO2 equivalent (CO2e) per kilogram of hydrogen. Blue hydrogen with high levels of methane leakage and low levels of CCS efficiency (55% capture) would emit 24 kilograms of CO2e. Blue hydrogen where methane leakage is virtually eliminated and CCS captures 93% of emissions would be roughly equivalent in carbon intensity to green hydrogen.

The hitch for environmental advocates: this has yet to be proven at commercial scale.

McCoy says industry can eliminate fugitive methane emissions relatively cheaply. David Layzell, a Calgary-based energy systems expert with The Transition Accelerator, a net-zero think tank supported by Canadian charitable foundations, says the technology should quickly become viable as carbon levies rise under a Liberal government plan to gradually increase the carbon price to $170 a tonne by 2030.

As with green hydrogen and other low-carbon technology, costs will come down as more projects are built, Layzell says, adding that newer technology is now promising to allow greater capture efficiency and less reliance on electricity from the grid that can be another source of carbon emissions. And in Canada, blue hydrogen plants will qualify for federal tax incentives, so long as the hydrogen isn’t used to spur production of oil from old wells in enhanced recovery projects.

South of the border, U.S. President Joe Biden’s Inflation Reduction Act includes the largest hydrogen subsidies in the world. Though it provides some funding for blue hydrogen, it has far greater incentives for green hydrogen producers. The bill – which passed in September – “immediately makes green hydrogen a competitive source of energy compared to its fossil fuel alternatives,” a briefing from law firm Shearman & Sterling said.

Natural Resources Minister Jonathan Wilkinson argues Canada needs to ensure it remains competitive with the United States in developing and deploying hydrogen technology. This week, the minister announced $800 million in funding from its Clean Fuels Fund for 60 projects, including hydrogen production and fuelling stations.

Will Canada end up being a blue or green hydrogen hub? Given the enormity of the energy transition challenge, governments with existing fossil fuel economies are unlikely to choose just one path. But they will have to closely monitor and regulate the sector to ensure that low-carbon promises are kept – and make any financial support conditional on verifiable evidence that hydrogen is truly low carbon.

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Nova Scotia is going to become a “clean, green energy superpower,” said the province’s environment minister, Tim Halman, at a media conference held in August to decry Ottawa’s imposition of carbon pricing in Nova Scotia. One of the ways the province would get there, he said, was “developing green hydrogen.”

Together with five new wind farms, green hydrogen would help the province reduce greenhouse gases and “preserve our planet,” Halman said.

Asked how green hydrogen would help Nova Scotia’s climate plan, Halman said that hydrogen is “one component” of it, adding, “I am very proud of those green hydrogen projects.”

There is currently only one green hydrogen project proposed for Nova Scotia. EverWind Fuels is planning a “green hydrogen production facility” in Point Tupper, on the Cape Breton side of the Canso Strait.

The project involves two phases, said Trent Vichie, New York-based CEO and founder of EverWind. The first will start in 2025 and produce hydrogen that will be converted to 200,000 tonnes of green ammonia that year.

In phase two, which should start in 2026, the plan is to produce a million tonnes of green ammonia per year, all destined for export to Europe.

Green hydrogen is produced from fresh water by a process of electrolysis. It is often used to make ammonia, which is easier to store and transport.

In phase one, the project will use 200,000 gallons (757,000 litres) of water a day from nearby Lake Landrie, or 2% of the lake’s capacity, Ken Summers, Environmental Affairs Advisor for Everwind, said in a phone interview.

The Colours of Hydrogen

Hydrogen is assigned colours based on how carbon-intensive its production is and how these relate to climate protection.

Summers said for the hydrogen and ammonia to be “green” they have to be produced using “100% renewable power.”

“Grey hydrogen,” for example, is the opposite of green hydrogen: it’s produced using natural gas or coal, with carbon dioxide released directly into the atmosphere. “Blue” hydrogen is produced using natural gas, but carbon emissions are meant to be stored or processed using carbon capture and storage technologies. However, blue hydrogen may not be an improvement over grey hydrogen because of methane leaks.

Hydrogen is an energy carrier that “can be used to store, move, and deliver energy produced from other sources.” It must first be manufactured from a primary energy source.

According to a 2021 International Energy Agency (IEA) report on how the world could achieve net-zero emissions by 2050, the combined share of low‐carbon hydrogen and hydrogen‐based fuels in total energy use worldwide would be 13% in 2050, while hydrogen and ammonia should contribute 2% of global electricity generation.

It is widely recognized that hydrogen will have a role in our future energy mix. But the jury is still out on whether all the recent hype about green hydrogen is warranted, or if, as electric vehicle columnist James Morris argued in Forbes, it is a “cult.”

In August, EverWind signed memoranda of understanding with two German energy companies—Uniper and E.On— each of which would potentially purchase 500,000 tonnes a year of the green ammonia produced in Point Tupper.

The ammonia will be shipped across the Atlantic Ocean, adding an as-yet-untallied source of carbon emissions if the ships are fuelled—as they likely will be—with highly polluting and carbon-intensive heavy fuel oil.

EverWind acquired a 7.8 million-barrel storage terminal at the site in Point Tupper from Texas-based NuStar Energy for $60 million in May this year.The terminal is supposed to be in “advanced stages of development” as a green hydrogen and ammonia production and export facility, EverWind said in a release. But Ken Summers said the company will be submitting its facility conversion proposal for environmental assessment to Nova Scotia this month.

Devil in the Confusing Details

It isn’t entirely clear how soon this “green” hydrogen project will have access to green power.

The project will be “powered off the grid” in the “immediate term and for quite a while,” Summers said. He noted that environmental assessments for wind projects are a much longer process, so the project would not be powered initially by wind farms.

The EverWind website states: “Our aim is to transform the province into a hydrogen hub of Eastern Canada and kick start a new green economy in the region by harnessing the power of the wind and other abundant renewable resources. In its second phase, the expanded project will be globally competitive, using local wind power sources as the green power supply for carbon-neutral fuel production.”

Asked where the wind power and “other abundant renewable resources” would come from, Vichie answered in mixed messages.

“Just the Nova Scotia grid,” for the first phase, he said. That grid is owned by Nova Scotia Power (NSPC), which the province privatized in 1992, and that has since given rise to Emera, a multinational energy company with $34 billion in assets in Canada, the United States, and the Caribbean.

Later in the interview, Vichie said that EverWind would be adding wind power to the existing NSPC grid for phase one, specifying that it would be “touching the Nova Scotia grid” and then going to the EverWind facility.

So it would be “misleading” to say EverWind would be “drawing from the grid” he added, as it would be “using the transmission lines to access renewables coming online.”

“There will be “new wind coming onto the system by 2025 that will be built for the plant,” Vichie said. He did not reply when asked where, exactly, the new wind power would be coming from.

He did specify that it would not be from any of the five large new wind projects that were announced for the province last month. Vichie said there were other wind projects “that didn’t make the cut” or other firms that “didn’t bother to bid” on the province’s request for proposals for the five new wind farms.

“So there are projects that are ready that aren’t being built,” Vichie said.

Unanswered Questions

NSPC spokesperson Jacqueline Foster said the five new wind projects will become operational by 2025. At that point, she said wind energy will account for about 30% of the electricity supply on the provincial grid.

But even by 2030, the year NSPC is to have eliminated coal from its energy mix, it still expects only 80% of its supply to come from renewables.

NSPC is also upping its use of biomass from boilers at Port Hawkesbury and Brooklyn in southern Nova Scotia, burning trees to produce electricity, which critics say is not carbon neutral, and have called a “travesty.”

And even with more renewables coming on stream, NSPC is likely to continue relying on its four coal-fired plants for some years to come.

So the hydrogen and ammonia produced with NSPC grid power in 2025 would be relying on an electricity mix that includes coal and 30% wind energy.

Unless EverWind is able to get permitting for and develop its own large wind projects by 2025, which would provide 100% of the electricity for the project, how, then, can the hydrogen and ammonia produced in phase one be called “green”?

“It’ll be green power because the power sources that we’ll be taking are 100% green,” Vichie said. “We’re actually working through a process to actually sort of certify orders. We build a new wind farm, it touches the grid, which has coal and everything else, that goes through our plant.”

“And it’s a really important point,” Vichie said. “If I build a new wind farm, it touches the grid, are there any more carbon dioxide emissions? No.”

He did not specify where EverWind plans to build a wind farm for the first phase.

Vichie also said that all the wind energy—for phases one and two—would be from onshore turbines. At some point, if other companies like Shell or BP develop offshore wind projects, EverWind’s facility could be a market for that electricity, he added.

“Further phases of the facility will be powered by offshore wind, which enables the production of over 10 million tonnes per annum of green ammonia and will be serviced by EverWind’s existing marine infrastructure,” an EverWind release states.

Where Will the Power Come From?

This brings us to the question of just how much electricity it will take to produce all that hydrogen and ammonia, which appears to be mostly slated for export.

For phase two, Vichie said the plant will depend entirely on wind energy, mostly from new projects across the Canso Strait, in Guysborough County on mainland Nova Scotia.

He said EverWind will need about 300 wind turbines for phase two, the same number of commercial wind turbines currently generating electricity for the NSPC grid.

Vichie said his company would not build wind farms where they are not wanted, for example along “the Cabot Trail, the Cabot Links golf course” in Inverness County. “That’s a beautiful part of Nova Scotia that has an amazing growing economic area.”

He contrasted this with Guysborough County on Nova Scotia’s Eastern Shore, where EverWind is looking to locate its wind projects.

“Guysborough County is round about two million square kilometres,” Vichie said. “You’ve got 3,000 homes in that two million square kilometre range. We’re talking about extremely low population density.” (This is not correct. Guysborough County is actually 4,000 square kilometres; the whole province of Nova Scotia is just 55,284. There are 4,897 private dwellings in the county, and 3,559 are occupied full time.)

Port Hawkesbury Paper has also planned a 130-MW wind farm for Guysborough County.

In recent years, there has been no shortage of corporations targeting Guysborough County for large industrial projects—from Maritime Launch Services’ proposed spaceport at Canso, to Pieridae Energy’s liquefied natural gas plant at Goldboro, to five open pit gold mines. This prompted Barbara Markovits of the Eastern Shore Forest Watch Association to dub the province’s Eastern Shore a “sacrifice zone.”

Guysborough County is also important habitat for several endangered species, including the mainland moose.

A 2019 Mi’kmaw Ecological Study done in response to a proposed gold mine at Cochrane Hill in Guysborough County pointed out that much of the region, known in the Mi’kmaw language as Esikikewa’kik, “is still in a relatively undeveloped state and contains significant areas of intact ecosystems in areas that have so far escaped the accelerated clearcutting activities of the past decade or so. It is, and has been since time immemorial, an important resource area for the Mi’kmaw of Nova Scotia.”

Asked about the risks of wildlife habitat fragmentation that wind projects could cause, Vichie said EverWind is working closely with First Nations and other local communities, and being “thoughtful” about where the wind farms would be placed.

In August, EverWind, calling itself a “renewable energy leader,” signed a memorandum of understanding with two Mi’kmaw corporations in Nova Scotia—Membertou Development Corporation and Paq’tnkek’s Bayside Development Corporation. The MoU states they are “supportive” of the project and are “aligned on clean energy.”

But the development of massive wind energy projects in Guysborough County is all for phase two.

There also remains the question of how much electricity will be needed for the project’s first phase in 2025.

Big Electricity Needs

Trent Vichie said it would take 250 megawatts, or “around 2 gigawatt hours (GWh),” to produce the 200,000 tonnes of ammonia in phase one. Vichie didn’t provide the formula he used to calculate the energy requirement, although he was asked.

His figures differ from the numbers provided by Dalhousie University professor of electrical and computer engineering Larry Hughes, a founding fellow of the MacEachen Institute for Public Policy and Governance.

To produce 200,000 tonnes of ammonia requires about 35,200 tonnes of hydrogen, Hughes said, citing conversion factors from the NEL Hydrogen website. It takes around 46.3 kilowatt hours to get one kilogram of hydrogen, so for 35,200 tonnes, it would take around 1,630 gigawatt hours (GWh) of electricity for the hydrogen, he added.

That would mean a production facility with a capacity of 274 megawatts operating continuously throughout the year, Hughes said.

However, since wind varies throughout the year, wind turbines only produce a fraction of the electricity they would have produced had the wind blown continuously. This is referred to as their “capacity factor”.

In the United States, the capacity factors of onshore wind turbines range from 0.26 to 0.52, meaning they generate electricity for one-quarter to half of the hours available in a year. So it would take far more installed capacity than 250 or even 274 MW to hit Vichie’s ammonia production target.

“The annual energy demand would be about 2,400 GWh to produce the ammonia,” Hughes said, “slightly more than 20% of NSPC’s annual production of 11,000 GWh.”

“The total energy required to produce both the hydrogen and the ammonia would be about 4,000 GWh,” he added.

So “we are confronted with the age-old question— where will the energy come from?” he said. “Four thousand gigawatt hours is about 40% of NSPC’s total annual production.”

NSPC should have more than this volume of green energy in 2025, but the utility’s other customers will need it as well, Hughes said.

“If EverWind had about 500 three-megawatt wind turbines running with an annual capacity factor of 30%, they could get the 4,000 GWh they need,” he said. “This would be independent of NSPC, although access to NSPC’s grid would probably be needed.”

But he pointed out that is just the electricity EverWind would need to produce 200,000 tonnes ammonia in the first phase. During that time, it seems the company would be getting electricity from the grid.

For phase two, the company has plans to produce at least a million tonnes of ammonia for export.

“One million tonnes of ammonia requires 12 million MWh [MWh] or 12,000 GWh for the year. Total hydrogen is 176,000 tonnes, requiring 8,149 GWh. The combined total is over 20,000 GWh per year,” Hughes said.

Nova Scotia’s total electrical demand is between 10,000 and 11,000 GWh per year, he noted. “The question is, again, where will the energy come from—in this case, for both the hydrogen and the ammonia, whether they produce 200,000 or 1,000,000 tonnes?”

EverWind needs to explain both, Hughes said.

Asked about the pressure this could put on Nova Scotia’s own electricity needs, at a time when the province is hard-pressed to reach its own deadlines to eliminate coal from the mix by 2030 and reduce its greenhouse gas emissions, Vichie replied that EverWind has told NSPC the hydrogen plant won’t need to be running 100% of the time. It could avoid stressing the system at times of peak need in the winter.

Asked if EverWind had been in discussions with Nova Scotia Power, spokesperson Jacqueline Foster said, “We are committed to providing customers with energy that meets their requirements and to working with hydrogen producers and regulatory stakeholders to understand what considerations may be required in designing tariffs to appropriately reflect considerations related to their potential service.”

This indicates that despite Vichie’s claims that EverWind would somehow have its own source of wind energy for phase one, the project does plan to use the NSPC grid in 2025.

Black Hydrogen, Not Green

And if that is the case, then how “green” will the hydrogen and ammonia it produces really be?

In 2020, Nova Scotia’s electricity grid emitted 670 grams of carbon (equivalent) per kilowatt hour (kWh), six times the national average.

It takes 50 kWh to produce one kilogram of hydrogen, said chemical engineer Paul Martin, a founding member of the Hydrogen Science Coalition. So if that kilo of hydrogen were being produced on the Nova Scotia grid in 2020, it would produce 33.5 kilograms of carbon dioxide.

“That’s 3.3 times as much as you would get if you just built a steam methane reformer and made hydrogen the normal way [with natural gas],” said Martin.

Although NSPC is expected to emit less carbon as more wind and hydro are added to the province’s electricity mix by 2025, its grid will still be a long way from being coal- and carbon-free just four years from now, when phase one is expected to be operational.

“As the project is based on using grid electricity, then it looks to me to be a pilot project,” Martin said.

And “it would be a pilot project that would not make green hydrogen,” He added. “It would make it very black hydrogen due to Nova Scotia’s grid’s very high carbon intensity.”

This article is republished from The Energy Mix and The Halifax Examiner. Read the original article.

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One observer said the two countries’ joint declaration of intent, which calls for green hydrogen shipments from Canada to Germany to begin in 2025, was likely the first global trade deal for renewable hydrogen or its more easily-transported derivative, green ammonia. In Stephenville, Trudeau called the bilateral commitment to build a trans-Atlantic hydrogen supply chain by 2030 a historic moment, CBC reports.

“We must look to resources like hydrogen which can and will be clean and renewable. We can be the reliable supplier of clean energy a net-zero world needs,” he said. “The need for clean energy is almost limitless, and that’s where Canada, and Atlantic Canada specifically, gets to step up. With our renewable resources, we have a huge advantage.”

“We believe that Atlantic Canada presents a huge opportunity for us, but also for Canada to contribute to a green energy transition,” Scholz said, adding that his country will be looking for 90 to 110 terawatt-hours of hydrogen by 2030. “Canada is a close and like-minded partner in the energy transition.”

The coverage of Scholz’ visit pointed to Russia’s invasion of Ukraine, and the intense energy supply crisis confronting Germany as a result, as the context for a faster shift to renewables. “”We cannot as a world continue to rely on authoritarian countries that will weaponize energy policy as Russia is, that don’t concern themselves with environmental outcomes, or labour rights or even human rights,” Trudeau said.

Yet “the joint declaration of intent makes clear the agreement is not legally binding and stipulates it will be up to Canada’s Minister of Natural Resources and Germany’s Ministry of Economic Affairs and Climate Action to keep track of whether it’s making progress on its goals,” the Globe and Mail writes. “The Canadian-German agreement sets no targets for volumes of hydrogen produced and contains no commitments of new money to help commence exports to Europe by 2025.”

Natural Resources Minister Jonathan Wilkinson said the volumes of product that Canada can export that quickly “are probably going to be modest,” acknowledging that the timeline is “very ambitious”. But that “reflects the fact that Germany sees how this can help them in their current context,” with an immediate need to break free of Russian fossil fuels as soon as possible.

“Part of this is being driven by the desire to displace Russian gas,” Wilkinson said.

But behind the bid for clarity and speed on the green hydrogen deal, Scholz’ visit featured a sequence of mixed messages on whether Canada and Germany see a future for liquefied natural gas exports from Canada’s East Coast.

Since the beginning of Russia’s war, Canadian fossil fuel companies have been pushing hard to resurrect LNG export schemes that had already been rejected for economic or environmental reasons. Analysts and observers have been explaining for months that the projects wouldn’t go into production in time to address Germany’s immediate need, and the country’s commitment to rapid decarbonization would soon wipe out the demand that would justify a longer-term import/export deal.

We believe that Atlantic Canada presents a huge opportunity for us, but also for Canada to contribute to a green energy transition.

-German Chancellor Olaf Scholz

As The Energy Mix reported last week, when the Canadian and German governments announced Scholz’ itinerary almost two weeks ago, neither the word “liquefied” nor the acronym “LNG” showed up in either official statement. Later news reports confirmed that LNG would not be on the agenda for the three days of deliberations.

But none of that stopped Trudeau and Scholz from confusing matters when discussions went live.

At a news conference in Montreal Monday, the two leaders “appeared to pour cold water on the idea of shipping Canadian natural gas to Europe,” with Trudeau pointing to the cost and complex logistics of shipping gas from Western Canada “to a still-unbuilt liquefaction terminal on the Atlantic coast,” CBC reports.

“One of the challenges around LNG is the amount of investment required to build infrastructure for that,” Trudeau said. “There has never been a strong business case because of the distance from the gas fields, because of the need to transport that gas over long distances before liquefaction.”

He said Canada’s “best” contribution to the global gas market would be to ship product to Asia (which brings its own set of serious challenges), or via pipeline to the United States, freeing up supplies that Germany could more easily acquire from other exporters.

While Canada would be willing to ease regulatory hurdles for LNG exports, “there needs to be a business case,” Trudeau added. “It needs to make sense for Germany to be receiving LNG directly from the East Coast. Those are discussions that are ongoing right now between our ministers, between various companies, to see if indeed it makes sense.”

Scholz agreed that any LNG deal would need a business case, “because if it’s too expensive, it will not fly.”

But Trudeau still held open the possibility that LNG bound for Germany might be “doable”, with Scholz adding that Germany “would really like Canada to export more” gas to Europe.

“As Germany is moving away from Russian energy at warp speed, Canada is our partner of choice,” he said, during a German-Canadian economic conference in Toronto. “For now, this means increasing our LNG imports. We hope that Canadian LNG will play a major role in this.”

“We are creating the atmosphere for very direct talks between the business sectors of Canada and Germany [to see] if there is something which could be done now in this very crisis,” the German chancellor told Power & Politics host Vassy Kapelos. “But this is part of the follow-up between the businesspeople of the two countries.”

One of the challenges around LNG is the amount of investment required to build infrastructure for that.

-Prime Minister Justrin Trudeau

In the fog of comments and counter-comments, it wasn’t immediately clear how seriously either leader was advocating for direct LNG trade between the two countries. “Asked if there had been developments making new Canadian LNG projects more likely since Monday, a government source with knowledge of the talks said there had been ‘no change’ and Scholz was ‘well aware of sort of the timeline that would be associated’ with new Canadian LNG,” Reuters wrote Tuesday.

At the same time, with winter approaching and its own supplies in doubt, Germany “is quite keen for gas from just about anywhere,” the Reuters source added.

Reaction from Canadian civil society reflected the layered message coming out of Scholz’ three-day visit.

“After months of discussions focussed on East Coast liquified natural gas (LNG), the visit results in a welcome shift in rhetoric and focus towards green hydrogen,” Climate Action Network-Canada said in a statement.

“At a moment when the Canadian fossil fuel industry has been intensifying its lobbying efforts and instrumentalizing the invasion of Ukraine to promote fossil fuel expansion, the Canada-Germany Hydrogen Alliance offers a glimpse of economic opportunity and job creation beyond oil and gas,” CAN-Rac added. “As Canada’s domestic ‘clean hydrogen’ strategy continues to blur the lines between renewable and fossil-based hydrogen, the Canadian government has the chance to learn from Germany’s clear categorization and focus on green hydrogen.”

“There’s something beautiful about wind power from Newfoundland and Nova Scotia blowing away petro-power in Europe,” added Greenpeace Canada Senior Energy Strategist Keith Stewart. “Fossil fuels are at the core of the current conflicts in Europe and around the world, whether they are paying for weapons or fueling climate disasters.  So it is great they’re signing a deal proving renewable energy is the way forward, even though they can’t quite bring themselves to shut the door completely on LNG just yet.”

But that opening still raised flags with some CAN-Rac member groups.

“While we are encouraged to see the new Canada-Germany agreement for production and export of green hydrogen, we are concerned that the door is being left open to blue hydrogen fuel,” said Keith Brooks, programs director at Environmental Defence Canada. “Blue hydrogen, produced from fossil fuels, is not a clean fuel, and in fact may contribute just as much greenhouse gas emissions as burning gas, or even more. The world needs truly clean, renewable energy sources now.”

“We welcome the race toward a zero-emissions economy,” said Louise Comeau, director of climate change and energy solutions at the Conservation Council of New Brunswick. “We need to run that race with fair rules of engagement for communities and companies,” and “liquefied natural gas is not a legitimate contestant in this race. It won’t cross the finishing line in time to help Germany or the planet.”

This article is republished from The Energy Mix. Read the original article.

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For months, Canadian fossils have been touting the possibility of shipping LNG to Germany to help the country cope with an energy supply crisis brought on by Russia’s war in Ukraine. Public speculation and behind-the-scenes lobbying have focused on three possible export terminals: Repsol SA’s Saint John LNG plant in New Brunswick, Pieridae Energy’s on-again, off-again scheme for a new export terminal at Goldboro, Nova Scotia, and far less likely, the C$14-billion Énergie Saguenay project that was soundly rejected by the Innu Nation and the Quebec government last July.

But none of those projects appears to have made the cut when Germany announced the chancellor’s itinerary for his Canadian tour. The words “liquefied” and “LNG” did not appear in a Saturday story in the Globe and Mail that had Trudeau and Scholz inking a deal “to jointly explore the production of hydrogen fuel in Canada for export to Germany.” Scholz’ stop in Stephenville for a hydrogen trade show will bring him close to the site of the proposed one-gigawatt, 164-turbine Port au Port wind farm, which would be linked to a 500-megawatt hydrogen and ammonia plant at the port of Stephenville.

Nor did LNG rate a mention in an announcement Saturday from the Prime Minister’s Office in Ottawa.

In addition to discussing peace and security in Europe, the two leaders will “continue collaboration on ways the two countries can work together to safeguard energy security, and accelerate the global transition to clean energy, including through secure access to key resources like clean hydrogen and critical minerals,” the PMO said. “They will discuss taking strong climate action through policies like pollution pricing” and talk about “bolstering science and innovation relations, and attracting investments, including in sectors like automotive and electric vehicle manufacturing, hydrogen and clean energy, and bio manufacturing and life sciences.”

Aversion to LNG

The growing emphasis on hydrogen is the result of continuing discussions between the two countries, and at least partly a reflection of a strong aversion to LNG on the part of a key partner in Scholz’ three-way coalition government, the German Green Party, a senior Canadian government source told The Mix. The push for LNG in both governments continues, but even if it succeeds, the Repsol plant—a facility that already exists, and would not likely need new permits or public hearings to retool its operations—is the only one that has a credible chance of proceeding.

Even then, there are serious questions about whether Repsol could convert its St. John facility for export in time to help Germany address a short-term gas shortage when the country is also committed (and legally bound) to rapidly drive down its greenhouse gas emissions.

In April, 2021, Germany’s Constitutional Court declared that the country’s 2030 emission reduction targets were insufficient, lacking in detail, and therefore violated the fundamental rights of citizens—including the nine youth climate campaigners who originally launched the case. A week later, then-finance minister Scholz announced a 65% emissions reduction target for 2030 and a 2045 deadline to bring emissions to net-zero.

For months, that fast timing has raised serious questions about any Canadian LNG exports to Germany. “If the typical offtake agreement in the LNG business is 20 years, and we want to be out of gas in 2045, there is not so much time for any of these projects to come online unless you find some other creative solution,” Gerhard Schlaudraff, deputy head of mission at the German embassy in Ottawa, told The Mix in May.

“Opening a new LNG export facility in five years would be irrelevant to the current energy crisis in Europe,” added Brian O’Callaghan, lead researcher and project manager at the UK’s Oxford Economic Recovery Project, in an early July release from the Sierra Club of Canada Foundation and the Council of Canadians. “Building a new LNG export facility in Canada sounds like an enormous stranded asset in the making.”

While Canada’s fossil sector is keen to set up export deals with Europe, Pierre-Olivier Pineau, a professor at Montreal’s HEC business school, said companies will need guarantees before investing in new infrastructure to make those deals happen.

“I’ve never heard Germany saying… ‘We are willing to sign a purchase contract for the next 20 years,’ so that it secures all the financial aspects of the project,” Pineau told CBC yesterday.

Canadian Natural Resources Minister Jonathan Wilkinson ruled out public subsidies for East Coast LNG projects in early July.

Green Means Green

A parallel conversation has been going on around the production process for any hydrogen that Canada exports to Germany. Today, Canadian hydrogen is mostly derived from fossil gas, so it’s labelled “blue” hydrogen if the resulting emissions are captured and stored or earns the dreaded “grey” designation if the carbon and methane pollution is simply released into the atmosphere. A project like the Port au Port wind farm would produce “green” hydrogen, and it wouldn’t need an eastbound pipeline from British Columbia, Alberta, or Saskatchewan to get the product to an export terminal.

Green hydrogen is also the only formulation that Germany would likely accept, Schlaudraff told The Mix in May.

“When we say hydrogen, we mean ‘green’ hydrogen,” he said. “The Canadian side, for very good reason, prefers to talk about ‘clean’ hydrogen. The situation in Canada is different, and we appreciate that. But the German funding instruments for the hydrogen economy are all geared toward green hydrogen,” and “if you look at the opportunities for Canada to export hydrogen to Europe, it is simply green hydrogen made from water and electrolysis, because of the huge potential of renewables in Canada.”

Canada’s Duty

On a trip to St. John earlier this month, Deputy Prime Minister Chrystia Freeland lent general support to the idea that Canada should try to ship out its share of the fossil energy Europe needs.

“I do think that energy security today, more than ever, is a question of security full-stop, and Canada’s really lucky,” she said, after a reporter asked whether Canada should be doing more to export LNG. “We have a lot of energy. I think it is a political responsibility for us as a country to support our allies with energy security.”

But despite “a very tough moment for many European countries right now,” she declined to endorse the Repsol plant in St. John as an export opportunity. “I think this is not the moment to pick specific projects,” Freeland said.

And while Enbridge Inc. CEO Al Monaco is urging Ottawa not to squander a “second chance” to enter the global LNG market, other factors are lining up against a rapid gas buildout. The new green finance taxonomy adopted in early July by the European Union sets an emissions standard that will be tough for gas to meet, analysts at Rystad Energy concluded later in the month.

Meanwhile, public opinion on both sides of the Atlantic appears to be solidifying in ways that would make a major LNG deal a tougher political sell. In Canada, a mid-July Léger poll for Clean Prosperity concluded that the majority of voters expect elected officials to deliver on credible climate plans despite high inflation. And CBC says an estimated 6,000 people from across Europe have joined a festival-like protest camp in Hamburg, Germany, arguing that the “climate suicide” of LNG is no solution to Germany’s energy crisis.

This article is republished from The Energy Mix. Read the original article.

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“If Canada is going to continue to prosper, we’ve got to skate to where the puck is going,” the minister told a virtual roundtable hosted by Corporate Knights and the Embassy of Germany. “Hydrogen is where the puck is going.”

While Canadian companies are already major providers of hydrogen-powered trucks and trains internationally, there has been a lack of large-scale projects domestically. That is about to change, O’Regan said. “Canada can lead globally on hydrogen,” he said, suggesting the hydrogen sector could generate 350,000 jobs in the country and reduce greenhouse gas emissions by 190 megatonnes by 2050. That’s equivalent to roughly a quarter of Canada’s current GHG emissions.

Canada is joining a host of other countries in adopting a strategy to commercialize clean-burning hydrogen, with progress required on the production, transportation and end-use of the fuel.

Currently, most hydrogen is made from natural gas in an emissions-intensive process, but it can also be made from water using clean electricity, generating a product known as “green hydrogen.” As well, producers can use natural gas but capture and sequester the carbon dioxide emissions, producing “blue hydrogen.”

Hydrogen is seen as a key solution for reducing carbon emissions in such diverse applications as long-haul trucking, rail and aviation; in heavy industry like steel-making and concrete; and in storing electricity generated from intermittent sources like wind and solar so that it can be sold when the demand requires it.

O’Regan provided no details on the federal strategy, which is due to be released before the end of the year. Corporate Knights has proposed that Ottawa spend $1 billion on research and development efforts over the next five years and another $8 billion over the decade to deploy hydrogen technology across the Canadian economy.

Last month, the Alberta government released a natural gas strategy that includes development of a hydrogen supply chain, starting with the production of the fuel from natural gas while capturing and sequestering carbon emissions.

The European Union, South Korea, Japan, Australia, the United Kingdom and several individual European countries have announced their own hydrogen strategies. Germany has one of the most ambitious plans, aiming to spend €9 billion over the next four years to help its industry and transportation sector transform to a hydrogen economy.

The German government has decided that hydrogen “is key to a sustainable economy and society,” Stefan Kaufmann, the country’s federal commissioner for green hydrogen, told the Building Back Better Together webinar. Germany will have to import up to 80% of the green hydrogen it will need and is looking at sources in Namibia, Australia and now Canada.

“Blue hydrogen” – produced from natural gas, using carbon capture and storage (CCS) technology – can still be a significant source of greenhouse gases that will be inconsistent with the goal of achieving net-zero emissions by 2050, said Raffaele Piria of the Berlin-based think tank adelphi.

He said CCS technologies remove on average only 80% of the CO2 emissions from the flue, while there are also fugitive methane emissions that result from the production and transport of the natural gas from the field to the factory.

Piria noted the industry’s goal is to slash by half the cost of producing hydrogen from water and clean power. “I strongly doubt it is worth pouring billions of dollars into CCS if in 10 years green hydrogen will be more attractive,” he said.

The colour scheme for hydrogen can be misleading, and the focus should be on measurable and certifiable carbon intensity, said Sarah Petrevan, policy director for the think tank Clean Energy Canada, which issued a report on hydrogen last month. European definitions of “green hydrogen” typically exclude the use of nuclear power, though the GHG intensity of that process can be quite low.

Petrevan said hydrogen could be an important fuel source for decarbonizing the sectors with the “toughest third” of Canada’s total emissions to abate. They include heavy industry such as steel and cement, marine transport, aviation and long-haul freight. In each of those sectors, hydrogen will have to compete with other solutions such as battery-powered electric motors.

The Clean Energy Canada report concludes that Canada can be a leader in both the supply of clean hydrogen exported to the world and in the industrial products that facilitate adoption of hydrogen in the modern economy.

However, Petrevan warned Thursday that many in Canada focus on the opportunities in hydrogen production, while the market for the fuel remains undeveloped: “Something is going to have to be done to stimulate demand domestically while we wait for the international markets to mature.”

A range of applications are currently being pursued. Indigenous communities are looking at hydrogen technology to replace their reliance on dirty and expensive diesel and to provide reliable power for their energy-deprived citizens, said Beaver Paul, a founder of SEN’TI Environmental & Indigenous Services, based in the Gaspé region of Quebec.

The company is working with partners on an ammonia plant that will use green hydrogen and is considering switching the community’s fishing fleet from diesel to hydrogen-fuel-cell engine.

“For remote communities, we believe hydrogen will play a big role in our futures,” Paul said.

Canada is fortunate to be among the world’s lowest-cost producers of zero- or low-carbon hydrogen, according to a report from Harvard University.

According to the non-profit Transition Accelerator, in provinces with ample low-carbon electricity (e.g. from hydropower, nuclear or renewables), electrolysis of water can produce “green” hydrogen for $2.50 to $5 per kilogram, and in provinces with low-cost natural gas and the geology suitable for permanently sequestering the by-product CO2, “blue” hydrogen can be produced at a price of $1.50 to $2 per kilo.

However, BloombergNEF forecasts that by 2030, green hydrogen will be cost-competitive with the natural-gas-derived fuel as a result of declining costs of renewables and the scaling up of hydrogen production.

Scores of start-up companies are pursuing innovations across the fledgling sector, from production of hydrogen to its transportation to applications for its end-use, said Farzin Shadpour, managing director for supply chain and logistics at Plug and Play, a major venture-capital provider and technology accelerator.

Global investors are keen to participate, Shadpour said, in the development of a market that BloombergNEF forecasts could supply a quarter of the world’s energy by 2050.

Shawn McCarthy writes on sustainable finance and climate for Corporate Knights. He is also senior counsel for Sussex Strategy Group.

With the support of the Embassy of the Federal Republic of Germany in Canada.

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That story goes far beyond the realm of turbo-powered supercars. California’s recent decision to ban the sale of all diesel trucks and vans by 2045 laid down the latest marker about the diminished role that fossil fuels are going to play in the future. And while hydrogen will be competing with electric vehicles for that market share, it’s clear that hydrogen is ready to take on a much bigger role than it has in the past as it expands into energy storage, heavy industry and transportation.

“I think we’re just in the first few months of a fundamental retooling of energy systems that could very well dominate for generations to come,” says Dan Wicklum, CEO of The Transition Accelerator, a pan-Canadian non-profit dedicated to maximizing Canadian opportunities in the ongoing energy transition.

By most accounts, Germany has taken an early lead in the race to dominate this new market. Its recently announced National Hydrogen Council will oversee a plan that includes €9 billion worth of investment in both research and companies that can help it meet its goal of five gigawatts (GW) of hydrogen capacity (the equivalent of five nuclear power stations) by 2030 and 10 GW by 2040. “The time has come for hydrogen and the technologies enabling its use,” said Peter Altmaier, Germany’s minister for economic affairs and energy, in July. “We must therefore harness the potential for economic output, employment, and the climate, and do this now.”

Germany isn’t alone in its belief that hydrogen needs to play a much bigger role in the economy of the near future. Last week, France rolled out €7 billion for the development of a hydrogen industry and other green technologies as part of its €100 billion green recovery package, aiming for 6.5 GW of installed capacity by 2030.

Europe’s broader hydrogen strategy calls specifically for 40 GW of green hydrogen-production capacity – that is, hydrogen produced from renewable energy like wind and solar – to be installed by 2030, with an additional 40 GW “in Europe’s neighbourhood with export to the EU.” That isn’t going to be easy. Next year, Spain’s Iberdrola is expected to finish building Europe’s largest dedicated green hydrogen-production facility, one whose hydrogen fuel will be used to help make fertilizers. But as Sebastian Kennedy noted in the Energy Flux newsletter, “To achieve only the within-EU 2030 target [for hydrogen development], Europe would need to build around 200 such facilities every year for the next decade.”

That’s where Canada can play an important role. Europe will try to get some of that hydrogen from North Africa, but the mismatch between the desired supply and the available capacity of hydrogen – and Europe’s obvious need to avoid depending too heavily on Russian imports – creates a perfect opening to build a new export-driven energy economy here. Wicklum says that opening is a function of the cost advantage Canada has in creating both blue hydrogen – that is, hydrogen derived from natural gas that, unlike so-called grey hydrogen, uses carbon capture technology to sequester emissions – and green hydrogen, which is the product of combining renewable energy with inputs like water and biomass.

And while Europe has indicated that it wants to rely entirely on the latter, it may need both blue and green hydrogen to meet its targets. The natural gas sector is hopeful. As James Watson, the secretary general of Eurogas, told Greentech Media, “They know that they won’t get to carbon-neutrality without it. It’s just I think that it’s difficult for them to openly say that.” That would be good news for Canada, which can provide both at very competitive costs. “Independent analysis has shown that Canada is about the cheapest producer of both green and blue hydrogen on the planet,” Wicklum says.

Maggie Hanna, the president of Common Ground Energy and a fellow with Alberta’s Energy Futures Lab, says that while hydrogen is currently being sold for as much as $30 per kilogram, it will soon settle at so-called diesel parity, or around $4 to $5 per kilogram. That bodes well for Alberta, which can produce blue hydrogen at much lower prices. “In Alberta, we can make hydrogen for $1.35 a kilogram, with sequestration, which will go to less than a buck when we have the proper carbon pricing regime in place,” Hanna says. That would require a $50 per tonne carbon price which isn’t much of a stretch from its current level of $30 per tonne. And while green hydrogen would cost more in Alberta, the province has plenty of wind and solar potential that could be tapped to make it.

Quebec’s enormous stores of hydroelectric capacity, combined with its proximity to global export markets, makes it a perfect place to produce green hydrogen – and that’s exactly what’s happening. In January, Quebec’s H2V Energies announced that it was opening its order book on a new plant that can turn residual residential biomass materials (such as waste wood and paper) into green hydrogen, one with an annual capacity of approximately 49,000 tonnes. And at an expected cost of $3.50 per kilogram (or US$2.68/€2.41), the company says that its hydrogen will be “less expensive than diesel fuel and defying all competition.”

Unlike proposed oil pipelines to the east and west coasts that have divided Canadians and sparked conflict and protest, a hydrogen pipeline could be a unifying force. “If you’re repurposing infrastructure to move a fuel that is not just compatible with, but required and necessary to have a net-zero future, then I think there’s the potential for common ground between these groups and regions,” Wicklum says.

So what will it take for Canada to seize this opportunity to reduce emissions, diversify its energy exports and unify an increasingly fractured country? The fact that Natural Resources Canada is in the process of designing a national hydrogen strategy is an important – and necessary – first step. But advocates like Hanna say we also need to align our regulations and standards with Europe – pronto. “In the same way that oil is traded around the world using the US dollar as its currency, hydrogen’s going to be traded on the euro because they were the first movers.”

The recently signed Comprehensive Economic and Trade Agreement between Europe and Canada will help with that integration process. But Canada still has important work to do if it wants to meet Europe’s growing appetite for zero-carbon energy. Getting there will require the kind of government support that is increasingly common in other emerging hydrogen economies such as Germany and France. For example, of the €9 billion Germany is allocating to green hydrogen development, €2 billion will be dedicated to creating partnerships with countries where green hydrogen can be efficiently produced.

Canada’s federal government seems inclined to make some aggressive bets right now. With Prime Minister Justin Trudeau promising that September’s throne speech will lay out an “ambitious green agenda,” it’s safe to assume that some of those bets will be made in the area of clean technology and energy. Natural Resources Minister Seamus O’Regan told the CBC, “Things are happening quickly…trends we saw before the pandemic have accelerated. We want to be ahead of it.” The Canadian Hydrogen and Fuel Cell Association has said it hopes to see the feds earmark $3 billion for hydrogen. The Corporate Knights Building Back Better report recommended that the feds create a multiyear $40.5 billion natural resources and EV fund, with $5 billion set aside to close research gaps, and crowd in an additional $105 billion in private sector investment.

But if that money doesn’t materialize, Canada may miss out on far more of it being generated down the road. “This is a competitiveness play over decades, where we need to be able to position ourselves to win economically and environmentally,” Wicklum says. “If we don’t, we just won’t be relevant.”

Max Fawcett is a freelance writer and the former editor of Alberta Oil magazine.

With the support of the Embassy of the Federal Republic of Germany in Canada.

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