But in the small Bavarian town of Geretsried, near Munich, a new geothermal plant is quietly signalling a paradigm shift for the industry, as recent technological advances have opened up new territories, enabling the production of clean, baseload power.

Calgary-based Eavor Technologies, a pioneer in what’s being called “next-generation” or “advanced” geothermal, is part of a small pool of start-ups that is borrowing technical expertise gleaned from the oil and gas industry to drill for heat far below the earth’s surface and send it back up as a source of low-carbon energy.

“It has one of the smallest footprints for power generation of any technology,” says Steve Grasby, president of Geothermal Canada, a non-profit that supports research and development of geothermal projects. “It’s also highly reliable; the power is always there. And it’s easy to ramp up and down as needed, unlike nuclear, which needs to run all the time.”

Eavor’s latest milestone was achieved on December 4, 2025, when it became the first geothermal company to deliver electricity to a commercial power grid at its Geretsried facility, demonstrating that its “closed loop” system is capable of supplying emission-free power at scale. For this project representing the culmination of a decade’s worth of research and development, Eavor bored sealed pipes nearly 4.5 kilometres into the earth, connecting more than 300 kilometres of boreholes underground. Now completed, the eight-megawatt electric and 64-megawatt thermal project produces enough electricity for 8,000 homes and enough heat for 120,000 homes. Another Eavor project is in the works in the Netherlands.

If geothermal is ever going to scale, it has to be a repeatable process you can do over and over. We think we’ve got the best way to do that.

– John Redfern, CEO, Eavor Technologies

The U.S. Air Force has also shown interest in advanced geothermal energy supply. In 2023, the Air Force began planning for two prototype-level geothermal projects at Mountain Home Air Force Base in Idaho and Joint Base San Antonio in Texas, awarding the Texas base project to Eavor.

Eavor believes its technology has the potential to generate power almost anywhere, and the firm has attracted hundreds of millions of dollars in venture capital with the promise of truly ubiquitous, dispatchable renewable energy. The venture capital arms of BP and Chevron have invested some US$40 million in Eavor, and, through the Canada Growth Fund, the federal government has funnelled $90 million to the company. Eavor has used investors’ capital on research and development to continue to scale up the number and size of its projects and trim costs.

Eavor is not the only player in the hydrothermal sector that is exploring new ways to dig for heat. Texas is a hub of innovation in next-generation geothermal power. Prominent start-ups, such as Sage and Fervo Energy, are based in Houston, which shouldn’t be surprising given that energy demand is surging in Texas, where Meta, OpenAI and Microsoft are building huge data centres.

In general, geothermal is becoming a growth sector as new drilling capabilities and other advances now enable projects to be developed across a much wider range of geologic settings than ever before.

What is geothermal energy and how does it work?

For more than a century, people have been using steam generated by deep underground water reservoirs that are heated by the earth’s mantle to power generators. Iceland and New Zealand get about 20% of their electricity from geothermal thanks to their volcanic landscapes, which host shallow, highly permeable underground heat reservoirs. Only a few sites on the planet, however, contain the geological conditions to support a geothermal system at scale, and geothermal contributes only a very small share of the world’s overall supply – approximately 16 gigawatts, representing less than 1% of total capacity installed worldwide. (The only commercial geothermal power plant in Canada is in Alberta, the Swan Hills Geothermal Power Project.) By comparison, wind and solar together supplied 17.6% of global electricity in the first three quarters of 2025, pushing the total share of low-carbon energy sources to 43%.

With the rise of next-generation technologies, geothermal could significantly raise its contribution to the world’s supply of renewable power. Key to both “enhanced” geothermal and “advanced” geothermal systems is that neither requires natural underground reservoirs. All that is required is the heat of the earth, which is available nearly everywhere.

Enhanced geothermal uses the fracking techniques of the oil and gas sector to drill into hot rock and create permeability.

Eavor’s advanced geothermal system forgoes fracking in favour of a closed-loop system. Started by veterans of the oil sector, Eavor has designed a kind of underground radiator where fluid is circulated through a closed loop of vertical pipes that connect a network of horizontal pipes deep within the earth. Absorbing heat from the rock, the temperature of the working fluid rises and is then pumped up to ground level to generate heat and power.

“If geothermal is ever going to scale,” Eavor’s chief executive, John Redfern, told The New York Times in 2023, “it has to be a repeatable process you can do over and over. We think we’ve got the best way to do that.”

Low risk, high rewards

Besides the scarcity of suitable locations, geothermal has long been hampered by its high capital costs, the bulk of which are spent on drilling, which can eat as much as half the cost of a project.

Still, as greater efficiencies are realized, costs are coming down – by an impressive 22% from 2021 to 2022 alone. Some systems are even cost-competitive with gas plants and cheaper than coal. Moreover, once built, geothermal is much cheaper to operate than other dispatchable sources like coal, gas and nuclear.

While some experts believe it possible to create geothermal energy almost anywhere, Grasby does offer a caveat. “You can’t really do this just anywhere. In some places, you may have to drill much deeper to get to the heat you need. Rocks vary in thermal connectivity; some rocks have high connectivity and others are low in connectivity. You need a certain temperature to make the system work.”

In Canada, as well, permitting and regulatory regimes have yet to catch up to the latest developments in the geothermal world. According to Grasby, only three provinces currently regulate geothermal energy production: Alberta, British Columbia and Nova Scotia.

Updates to regulatory frameworks may yet emerge should the momentum behind geothermal continue, especially given that hydrothermal offers round-the-clock, on-demand power, unlike wind and solar.

New analysis from the International Energy Agency forecasts next-generation geothermal as representing up to 800 gigawatts of clean electricity capacity by 2050 – roughly 50 times the world’s current geothermal capacity of around 16 gigawatts.

Analysts at Ember, a U.K.-based energy think tank, anticipate that geothermal will quickly accelerate, reporting that by 2030, nearly 1.5 gigawatts of new capacity is expected to come online each year globally, three times the level added in 2024. By 2050, geothermal could meet up to 15% of the growth in the world’s demand for clean power.

As a net-zero economy looks increasingly precarious, the latest geothermal breakthroughs offer a solution to the supply of firm, low-emission energy thanks in large part to the tools and expertise that originated in the oil field.

Victoria Foote is a writer and editor who specializes in clean energy and climate.

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This story was originally published by Canary Media. It has been edited to conform with Corporate Knights style.

XGS Energy, an advanced-geothermal start-up, says it has completed crucial testing that proves its novel technology can operate reliably at commercial scale – without losing a drop of water in the process.

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But from those depths comes another chapter in Fort Nelson First Nation’s energy story, one that is green, and that it controls. Using royalties that the band office received from oil prospectors over decades, the community is now embarking on an entirely different transformation, looking to the future and developing a geothermal plant out of an orphaned oil well. It’s called Tu Deh-Kah, a Dene phrase that translates to “boiling water.” The First Nation hopes that the plant will go online in 2027, becoming one of Canada’s first electricity-generating geothermal facilities – and possibly the first one to be purely geothermal. Currently, the only large-scale plant is the dual natural gas and geothermal Swan Hills project in Alberta.

“We want to see a sustainable energy project in our territory that we own,” says Taylor Behn-Tsakoza, a community liaison officer with Tu Deh-Kah.

For Jim Hodgson, CEO of Deh Tai Corp., Fort Nelson First Nation’s economic development company, the project is steeped in pride.

Tu Deh-Kah is 100% Indigenous-owned and poised to generate seven to 15 megawatts, nearly enough to power the First Nation and Fort Nelson, the adjacent municipality of the same name.

Hodgson is an old-school oil and gas man who has worked in the industry for decades. Now, he is carrying over his expertise, and he’s not alone. Many in the First Nation have worked in the oil and gas sector, which Hodgson says gives them a skill set that transfers well to geothermal development. The burgeoning industry presents new opportunities for First Nations as the world drives toward an energy transition that leaves fossil fuels behind.

First Nations, Inuit and Métis people are already at the forefront of the energy transition in Canada, as partners in or beneficiaries of roughly 20% of the country’s electricity-generating infrastructure – virtually all in renewables. But oil and gas remains the largest private employer of Indigenous people in Canada, with 10,800 Indigenous workers, according to the most recent data from Ottawa.

As Indigenous communities around the globe forge transnational understandings of how to ensure that their interests are protected, can this renewable power help First Nations transition to the net-zero age?

The ‘whole moose’ approach

Tu Deh-Kah is not a traditional geothermal power-generating plant. For decades, geothermal has relied on the extreme heat of volcanic and high-temperature regions. But unlike the geyser-powered plants of Northern California or the volcanic heat of New Zealand, this project relies on a newer form of geothermal rooted in the sedimentary basin of Western Canada, which has traditionally housed rich oil and gas fields. “But there is a lot of heat in the earth,” says Jeremy O’Brien, the energy segment director for Seequent, a geoscience company that works closely with geothermal proponents to map the subsurface for geothermal projects.

Geothermal power plants do not burn fuel to generate electricity; instead, hot brine is pumped from deep inside the earth and used on the surface as direct heat or to produce electricity. All told, the plants emit 97% less acid-rain-causing sulfur compounds and 99% less carbon dioxide than fossil fuel power plants of similar size, according to the U.S. Energy Information Administration.

Traditionally, geothermal projects in volcanic regions can run as hot as 250°C to 300°C. In contrast, Tu Deh-Kah expects its heat to operate between 107°C and 120°C. The lower heat means less power-generation efficiency, which is partly why projects on sedimentary-basin geological formations are lagging behind volcanic or geyser-based ventures. But O’Brien thinks there is an opportunity for oil and gas regions to transition to geothermal plants within basin regions. There is both expertise in drilling and deep knowledge of the subsurface, he says. “I think the technological crossover is really important.”

Tu Deh-Kah also carries the ethos of what Behn-Tsakoza calls the “whole moose” approach. “When we harvest the moose, we use everything; you would never even know we were there.”

We want to see a sustainable energy project in our territory that we own.

— Taylor Behn-Tsakoza, community liaison officer, Tu Deh-Kah 

For example, the Tu Deh-Kah team plans to use the gas that remains deep in the old well to ensure that every element of the project is given a use, as if it were a moose. The First Nation is also exploring methods to extract lithium, a coveted critical mineral in the energy transition, from the brine, which it can then sell. And it has finished building a 2,000-square-foot greenhouse near the community’s school, Behn-Tsakoza says. It is the first of several that the First Nation plans to heat with the geothermal plant. The ambition is to grow enough commercial produce to “feed the North,” she says. Fort Nelson is an hour and a half south of the Northwest Territories border and on the transportation route to Whitehorse.

“Who knows what the future holds,” Behn-Tsakoza says. It’s a message she has tried to get across at dozens of community meetings, where she explains the project to local residents and receives their input and concerns.

Hodgson notes that the band office has held the project to the same standard that it would apply to any other company. “We don’t get it passed just because we’re owned by them,” he says. Band administrators conducted the required environmental and archaeological assessments and the project is now awaiting a final investment decision from the community’s council and membership. In February, the project received $1.2 million from Natural Resources Canada through the Indigenous Natural Resource Partnerships program, which is designed to increase the participation of Indigenous communities in the clean energy economy.

At the grocery store, Behn-Tsakoza sometimes runs into Elders who have their doubts about the project. “Has the project failed yet?” they’ll ask her. “Nope, I don’t think it’s going to,” she responds.

The reality is that geothermal in sedimentary basins remains relatively unproven on the continent. That has led to skepticism of the project’s viability, and its green credentials.

The Elders thought they had a “told-you-so moment” recently when project proponents discovered a lot more gas underground than expected. The former oil well extended approximately 1,500 metres into the earth; the geothermal project goes deeper, some 2,000 metres. But more sour gas remained deeper in the well than initially projected, and the geothermal project ran into it, raising an engineering and operational problem for the Tu Deh-Kah team, who are now figuring out what to do with it.

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Since the discovery, Behn-Tsakoza has been hearing it from Fort Nelson Elders at the grocery store. “See, this project isn’t going to be as clean as you think,” they say. “Whoa, whoa, whoa: our mission hasn’t changed,” she tells them – that is, to reap the benefits of a truly sustainable project. “Our vision hasn’t changed.”

Fort Nelson First Nation is not the only Indigenous community to cast its eyes to the promise of geothermal, though not without a strong sense of caution.

Jessica Eagle-Bluestone acts as an Indigenous liaison for Geothermal Rising, an international geothermal industry association. She says many tribal nations in the United States are “waiting to see if the technology improves more over the next couple of years” before venturing in. She says a lot of economic and structural risk remains with some old oil wells, depending on their integrity. But she believes there’s opportunity. While studying at the University of North Dakota, Eagle-Bluestone won a U.S. Department of Energy competition for developing a concept for a project to convert an old oil well in her home community in North Dakota into a geothermal plant. “It’s definitely on the radar of tribes,” she says.

O’Brien says that North American developers just need to look to Europe for successful sedimentary-basin geothermal developments. In Paris, geothermal is powering around 250,000 homes. In Munich, numerous geothermal plants provide a significant chunk of the city’s heating. “We see that potential starting to roll through,” he says.

The Dixie Meadows warning and the Indigenous geothermal declaration

Like any major energy project, geothermal development can fall victim to mistakes and the antipathy of Indigenous Peoples, often as a result of poor site selection and lack of meaningful consultation.

In Dixie Meadows, Nevada, a controversial geothermal project has led to court challenges from the Fallon Paiute Shoshone Tribe and the Center for Biological Diversity. The project’s plant is proposed to be built on a spiritual site for the tribal nation, cutting off the community from the location that is home to their creation story. The site is also home to a unique species of toad that is at risk of extinction if the project goes ahead.

The main issue here has been a lack of meaningful consultation that incorporates the interests and values of the Fallon Paiute Shoshone. Scott Lake, a litigator for the Center for Biological Diversity, says that during the consultation there was an emphasis on “process over outcome,” which didn’t take the concerns of the tribe seriously. As a result, the community launched a legal challenge over concerns about the impact the project would have on its religious and historical site. “No one started out on a crusade against geothermal energy – it just happens to be right where they view their creation site,” says Lake, who is working with the Fallon Paiute Shoshone to litigate against the project. “I mean, it’s just a really terrible place [to put it], and that’s the issue we’re dealing with.”

For Lake, unless thoughtful decisions on site selection are informed by meaningful consultation and free, prior and informed consent, projects like the geothermal plant in Dixie Meadows will run up against opposition. He says the United States is behind other countries in upholding the spirit of the United Nations Declaration on the Rights of Indigenous Peoples (UNDRIP) and its meaningful- and early-consultation principles. “At the end of the day, it’s an efficiency issue,” he says. “Do you want to push through projects that are going to get litigated and delayed, or do you want to find, you know, situations where there’s not as much conflict?”

Do you want to push through projects that are going to get litigated and delayed, or do you want to find situations where there’s not as much conflict?

— Scott Lake, litigator, Center for Biological Diversity

A bid to chart a better path forward emerged last year at the first-ever Indigenous Geothermal Symposium in Hawaii. Indigenous leaders in the geothermal space came together and developed the Geothermal Indigenous People’s Declaration. The declaration calls on the wider geothermal community to uphold UNDRIP, to consult early in the process and to ensure that Indigenous nations benefit from the project, while not compromising their duties as land stewards.

Aroha Campbell is a kaitiaki consultant and one of the leading voices in developing the declaration. Decades ago, she saw geothermal plants built across the Maori homeland without benefits to local communities. She has dedicated her career to changing that equation and has negotiated partnerships with geothermal developments that earmark funding for Maori community initiatives, including cultural camps and housing.

For Campbell, the declaration is a starting point for all Indigenous nations across the world wrestling with the potential and pitfalls of geothermal. Campbell believes each Indigenous nation can take the declaration to their homelands and place it on the negotiating table with developers. The hope is to help the industry understand what working with Indigenous nations on geothermal projects will look like. Until then, Indigenous nations must keep their networks among kin strong.

“I believe the best thing that could happen for Indigenous people in geothermal is sharing,” Campbell says. “The good and the bad, and that sharing of the stories in regards to the developers as well, and the likelihood that all of our stories are very similar.”

Matteo Cimellaro was the Indigenous affairs reporter for Canada’s National Observer, with whom this story is co-published. He now reports on the public service for the Ottawa Citizen.

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Some important developments are coming for this year, including the ways in which we plan cities, emerging applications for artificial intelligence in the energy transition, and the comeback of traditional ideas about how we design buildings in a warming climate. Here are four trends to keep an eye on. ‘

AI and renewable energy

The broad acceleration of both private and public investment in renewables, charging stations for electric vehicles, and electric heat pumps is continuing to amplify the complexity associated with managing electricity grids on both the supply and demand sides of the energy market. According to industry experts, the massive uptick in both AI computing power and emerging applications for large language models holds out the promise of sharply improved demand forecasting and grid management systems.

“Consulting firm Indigo Advisory has counted more than 50 possible uses for AI in the energy sector,” Reuters reports. “The company estimates that 100 vendors have already introduced AI solutions into their products and that the market for AI is now worth up to US $13 billion in the energy sector alone.”

In a commentary published in December, the IEA noted that links are deepening between the power system and the transportation, industry, building and industrial sectors. “The result is a vastly greater need for information exchange – and more powerful tools to plan and operate power systems as they keep evolving.”

The inputs run the gamut from the growing inventory of solar and wind farms to the data that is gathered by sensor-based home heating systems and shared with utilities or equipment providers.

Other highly promising applications, according to the IEA, include the use of machine learning algorithms and the deployment of sensors on grid assets like power lines to predict the maintenance requirements and thus reduce downtime in order to optimize energy production.

‘Unplanning’ reaches critical mass

Urbanists have understood for many years that dense, compact cities represent the most effective way to build low-carbon urban regions. But zoning laws and seemingly bottomless highway budgets have long conspired to produce, in North America anyway, a tenacious sprawl cycle that has greatly exacerbated global warming.

Yet the housing affordability crisis that has inundated big cities in many countries seems to have finally forced local, regional and national governments to cast aside some of the most sacrosanct principles of planning in favour of blanket “up-zonings” and a broad relaxing of other rules governing development and parking.

This epochal shift in outlook, akin to changing the direction of an ocean liner, didn’t begin last year, but it feels like 2023 will be remembered as a critical turning point – the moment when the post-World War II  planning consensus finally gave up the ghost.

Justin Trudeau’s Liberal government took the constitutionally risky step of using lucrative federal “housing accelerator” grants as a carrot/stick technique to force municipalities to increase minimum residential densities across the board, and the seeming success of this initiative has attracted the attention of a growing number of cities of various sizes.

In the U.S., Minneapolis, California and Oregon have led the way with zoning reforms that triggered a boom in so-called accessory dwelling units (small rear-yard dwellings) and multi-unit residential buildings with significantly less on-site parking. Last year, a bi-partisan “YIMBY” act was tabled in Congress and aims to provide a similar set of incentives as Canada’s Housing Accelerator grants. Also as in Canada, the momentum and expert consensus behind such reforms – which expand supply but don’t necessarily create a lot more affordable housing – means they’ll almost certainly spread to many other parts of the U.S. in the coming year.

The single-staircase ‘radicals’

For decades, multi-unit residential buildings have been required, and with good reason, to provide at least two sets of exits/entrances to satisfy fire safety regulations. But for generations prior to the advent of such rules, many apartment buildings, especially low-rise ones in the core areas of older cities, were constructed around a single central stairwell – a configuration that allowed apartments to have not only more exterior windows but also cross-breeze ventilation. (The staircases often encircle an elevator shaft.)

Why? The central staircase in those older buildings allowed units to, in effect, straddle a corner, which means that windows could be opened in such a way as to allow the air to flow through, thus providing inexpensive and low-carbon cooling and ventilation. In the apartments of the fire-code era, by contrast, apartments tend to be situated on either side of a central (aka “double loaded”) corridor, which means there’s no possibility of cross-ventilation.

Numerous climate-minded architects have been trying to crack the riddle of how to bring back single-staircase design without compromising safety. The other benefits, according to proponents: more efficient use of space, better light, better apartment floor plans, including layouts suitable for families with children.

A related trend is the design of mid-rise European-style apartment blocks built around a central courtyard and, crucially, single-loaded corridors that overlook this space. These corridors also permit cross-ventilation – they can be outdoor spaces or enclosed but with windows that open on one side into the apartments and on the other onto the courtyard space.

In North America, California is leading the push to reform its outdated building codes. Last October, the state legislature set in motion a process to develop changes to the building code meant to allow single-exit multi-family buildings.

Will 2024 be geothermal’s breakout year?

The prospect of tapping into the energy from the earth’s molten core has long been seen as one of the most promising forms of low-carbon heat. Volcanic regions, such as Iceland or central Turkey, have an abundance of relatively shallow reserves and do in fact rely extensively on geothermal energy. But in areas where the earth’s heat is much deeper, the cost of bringing geothermal energy to the surface has remained economically prohibitive.

In 2023, however, policy-makers in the U.S. and Canada stepped up investments in geothermal systems, through, for example, the Inflation Reduction Act’s 30% tax credit and a $200-million loan by the Canada Infrastructure Bank to Enbridge Sustain, which builds and operates residential clean energy systems. This could be geothermal’s breakout year.

Much of that funding is directed at stoking the geothermal heat-pump market for residential use, and in particular new subdivisions. In Barrie, Ontario, for example, Enbridge is partnering with a local builder, Sean, to construct a 73-unit development that will use geothermal, as well as other green building techniques, such as solar shading and cross-laminated timber.

Yet the development of large-scale, commercial geothermal power plants to provide baseload energy remains in its infancy in much of North America (except for hot spots in places like California), despite the enormous potential and falling costs due to technology improvements, which make it competitive with coal, nuclear and some solar applications.

The Swan Hills geothermal power project in Alberta came online in early 2023, and several others in Western Canada are in the pipeline. While the U.S. is the world leader, with more than 3,500 megawatts of geothermal capacity, countries like Indonesia, Turkey and the Philippines have seen substantial new investment in recent years, the IEA says.

At least one Canadian venture, Deep Corp., has raised $52 million in private and public capital to use spent oil and gas wells in Saskatchewan as conduits for accessing geothermal reserves. Its plant is expected to come online next year.

The post All is not lost: Four climate-saving trends for 2024 appeared first on Corporate Knights.

Now that day seems to be dawning. It’s not the energy source that has changed; from as early as the Paleolithic era, humankind has exploited the heat within the earth for bathing and washing in hot springs. Now we know that constant energy source originates in the earth’s molten core, estimated to be 6,000°C, comparable to the temperature of the sun. That heat is a constant and, thanks to radioactive decay, expected to remain so for billions of years.

What has changed, however, is the state of technologies required to access that energy and, more importantly, a growing global consensus that, in an era of climate change, this low-carbon energy source needs to be fully exploited.

“Geothermal is the best of the renewables,” says Grasby. Unlike wind and solar energy, which are intermittent and require battery storage, geothermal can provide baseload power. It is also dispatchable, meaning that its generation can be calibrated according to demand, setting it apart from nuclear energy. And geothermal energy is incredibly diverse in its applications, with a spectrum ranging from electricity generation through direct heating and cooling systems, with additional possibilities for greenhouses, aquaculture and carbon capture.

Geothermal production is surging worldwide. Iceland, which began drilling geothermal wells in the mid-19th century, now heats 85% of its houses with geothermal heat and generates roughly a third of its electricity in geothermal power plants. Among the fastest-advancing geothermal countries are Turkey, whose geothermal electric production has increased 100-fold in the last decade, and New Zealand, whose volcanic zones currently supply 17% of its national grid.

The United States, blessed with the largest dry steam reservoir in the world – the Geysers of northern California – has the greatest total installed geothermal capacity, with 93 power plants generating 16.7 billion kilowatt hours of geothermal energy throughout the year. That’s still just 0.4% of American electric generation. In an effort to spur on the sector, President Joe Biden recently announced funding of up to US$20 million for projects that improve drilling efficiency, recognizing that geothermal’s heavy upfront costs are a major impediment to investment and growth.

In a world of steadily increasing geothermal capacity, Canada is often cited as a laggard. It’s the only country along the Ring of Fire – the belt of intense seismic activity that runs beneath the Pacific Rim countries – that has yet to feed geothermal power into its grid. But Canada’s negligible performance says less about a lack of determination or ingenuity than about geography and economics. And as the latter shifts – with the rising price of carbon (thanks to a national tax on carbon) and the surging cost of natural gas – Canada’s back-of-the-pack position is set to change. It is expected that Canada’s first commercial geothermal power project, developed by Deep Earth Energy Production (DEEP) in southern Saskatchewan, will be up and running by 2024.

“The potential here is huge,” says Grasby, and he would know, having spent the decade between 1975 and 1985 charting the country’s geothermal potential for the Geological Survey of Canada. The initiative was driven by the energy crisis of the 1970s and the resulting determination to reduce Canada’s dependence on oil. Research scientists drilled wells, and the first geothermal power was produced – but never connected to the grid. As the crisis passed and the price of oil sank, so too did enthusiasm for geothermal development.

It’s easy to be cynical about climate conferences and targets and posturing, but what I see happening with geothermal is really exciting. This energy transition represents the greatest economic opportunity in the last century.

—John Rathbone, engineering consultant

For 15 years, the results of Canada’s first geothermal program mouldered in garages and basements. But come 2000, with the rise in oil prices and a growing interest in renewables, Grasby was tasked with reassembling and digitizing the dusty data. The resulting 2012 report concluded that “Canada’s in-place geothermal power exceeds one million times Canada’s current electrical consumption” while also acknowledging that only a fraction of that power could realistically be produced.

To generate electricity from geothermal heat, a confluence of factors is needed: just the right temperatures, rock porosity and water pressure. In Canada, those conditions exist, deep in the volcanic rocks of the Pacific coast and the Western Canadian Sedimentary Basin that arcs down from the Northwest Territories through northern B.C., Alberta and southern Saskatchewan. But the question is precisely where they lie. The prohibitive expense of exploratory drilling nudges geothermal producers into collaboration with their wealthier energy cousins in the oil and gas sector.

Iceland now heats 85% of its houses with geothermal heat and generates roughly a third of its electricity in geothermal power plants.

“You’ve got a six-square-mile field that is surfacing hot water, 70-plus people who know how to work it, and over 60 years of historic data on its geology and chemistry,” says Lisa Mueller, CEO of Calgary-based FutEra Power, describing a typical legacy oil field in western Canada.

What many would see as a relic of the dirty energy past, Mueller sees as the basis of a clean energy future. Mueller is working on Canada’s first co-produced geothermal and natural gas power project. She expects the company’s pioneering plant, located in the Swan Hills of central Alberta, to be grid-connected by summer. Initially, two-thirds of the plant’s 21 megawatts will be derived from natural gas, and one-third from geothermal heat. But in a second phase, the plant’s hot water reservoir will be used to sequester carbon, and ultimately – Mueller predicts by 2025 – the plant will be operating at net-zero emissions.

Mueller, who once worked for oil behemoth Shell, has become a fierce proponent of low-carbon energy production. “It’s going to take an unparalleled effort to get us where we need to go,” she says. She’s convinced that the Swan Hills project will demonstrate a technical path forward for the oil and gas industry, in Canada and beyond. Grasby agrees.

“Geothermal presents incredible opportunities for Canada’s petroleum industry,” he says, adding that its geological knowledge and technologies will be key to geothermal development.

Beyond power production, geothermal energy is poised to play a significant role in Canadian heating and cooling systems. This makes good climate sense; while our grid is largely low carbon, thanks to an abundance of hydro and nuclear energy, Canada’s heating needs are currently met almost exclusively with fossil fuels. And those needs are great, accounting for some 60% of the country’s total energy consumption.

Sharleen Gale is Chief of the Fort Nelson First Nation, located in northeastern British Columbia and close to Clarke Lake, the province’s oldest natural gas production area. About a decade ago, as Gale was looking for economic development opportunities for her community beyond the depleting gas reservoir, an observation struck her. “When you drove along the pipeline,” she said, “you saw the melted snow all around it.”

For a remote, northern community, this seemed an incredible waste. Gale applied for a provincial grant to study the area’s geothermal potential, and now, with a major investment from the federal government, the Fort Nelson First Nation is using the Clarke Lake infrastructure – roads, well pads and wells – to develop a $100-million geothermal project that will not only produce power for the B.C. grid but also heat 14,000 local homes, as well as greenhouses to grow food.

Gale is hugely excited about what the Tu Deh-Kah (“water steam” in the Dene language) Geothermal project could mean for her community: energy self-sufficiency, food security and economic opportunity. With pride she explains that the project’s first two employees are community members who have returned to the remote First Nation following their university studies. “This project will protect who we are,” she says.

But the potential for geothermal heating in Canada is by no means limited to the North. Unlike geothermal power generation, which requires deep drilling to access temperatures upwards of 100°C, geothermal heating and cooling – also known as geo-exchange systems – involve lower temperatures, shallower wells and smaller bore fields. The idea is to create a kind of thermal piggy bank: sinking surface heat into the earth during hot months, to be extracted with pumps to heat buildings during cold months. The principle can be applied to single dwellings or at the “district” level of a university campus, condo development or subdivision. According to the Sustainable Technologies Evaluation Program, there are currently over 100,000 geothermal heating and cooling systems operating across Canada.

“This project will protect who we are.”

–Sharleen Gale, chief of the Fort Nelson First Nation, on the Tu Deh-Kah Geothermal project

The University of Toronto is building a geo-exchange system under its downtown campus, destined to be the largest of its kind in urban Canada and to reduce the university’s greenhouse gas emissions by 15,000 tonnes of carbon dioxide equivalent by 2024 – equivalent to taking 3,260 gas-powered cars out of circulation. According to John Rathbone, a Guelph-based engineering consultant, projects of this kind are proliferating across southern Ontario.

Rathbone runs a low-carbon energy consultancy, and in the four years of its existence, he has seen the interest in geo-exchange systems move from a climate-conscious, progressive fringe toward the bottom-line-driven centre. He attributes the shift to carbon pricing, the private sector’s growing commitment to ESG (environmental, social and governance) principles and the Toronto Green Standard, the city’s increasingly rigorous catalogue of environmental building standards, which is impacting development in other municipalities as well.

“It’s easy to be cynical about climate conferences and targets and posturing,” Rathbone says, “but what I see happening with geothermal is really exciting. I actually think this energy transition represents the greatest economic opportunity in the last century.”

Grasby shares his optimism. “Canada is on the cusp,” he says, citing the number of geothermal project “firsts” on the immediate horizon. He believes that once their success has been demonstrated, the investment floodgates will open and that if provincial governments create proper regulatory frameworks, Canada will enter what some are heralding as geothermal’s golden age.

Naomi Buck is a Toronto-based writer.

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That very approach that helped unleash the economic potential of Alberta’s oil sands can now be reimagined to drive progress to the growth markets of the future. In the low carbon economic transformation, Canada is well equipped to lead the way and supply growing global markets with zero-carbon products and technologies.

There are three key ingredients from AOSTRA that should inform government support for decarbonizing and diversifying our economy:

1. Right goal: Investment should avoid areas that involve incremental advances and focus instead on aspects that leverage innate competitive advantages, are disruptive and go beyond immediate commercial interests.
2. Right structure: Full backing and long-term capital from government, but independently delivered.
3. Right scale: Sufficient funding to realize the goal while taking into account available human and natural capital as well as industrial infrastructure.

If the federal government, working in partnership with provinces, takes this type of proactive approach now, it can help struggling regions thrive in the transition to a net-zero economy. Doing so will help to diversify Canada’s commodity risk, insulating us from the whims of a volatile global market that is vulnerable to structural disruption as the electrification of vehicles threatens up to one-third of the demand for crude oil.

The great strides made in the oil sands since 2000 in terms of GHG and cost reductions put the industry in good stead to supply global markets for some time to come, albeit with margins likely much slimmer than the industry used to enjoy. There now remains little doubt that disruptive large-scale growth opportunities are no longer centred on combustion of fossil fuels, but rather on what the Energy Futures Lab calls future-fit hydrocarbons, which include carbon fibres, activated carbon, hydrogen and sustainable aviation fuels.

The oil and gas extraction sector directly employs roughly 100,000 salaried and hourly people. It contributed 5.6% of our GDP in 2019 and provided $131 billion in annual export revenue last year, up 32% from 2015 (when oil prices hit a valley), but the value of exports is expected to drop significantly in 2020. Alberta Innovates estimates that oil sands revenue (which represents about two-thirds of Canada’s five million barrels per day of oil production) will dip to $27 billion in 2020.

The sector’s vulnerability to downturns in the global market puts Canadian workers and our economy at risk. During the most recent crash in oil prices, Rystad Energy said that “Canada leads the list of those in trouble” as Canadian oil companies plan to reduce production and capital expenditures to $14.5 billion – down 21% from the 2016 to 2018 average. Company restructuring plans are now emerging as investors seek greater returns in light of market volatility. Cost containment pressure and the move to automate the industry could lead to fewer, not more, jobs in Canadian oil- and gas-producing regions. An estimated 7,700 jobs were already lost in the Canadian oil and gas sector between March and April of this year.

As an illustration of the oil sector’s long-term decline, energy ​stocks’ share​ in the S&P 500 has fallen from a recent highpoint of 14% in 2009 to less than 3% today.

The opportunity

While the pandemic-induced market crash of the last few months was triggered by an unprecedented situation, the outlook for the sector was already troubled before COVID-19. The one-third drop in oil demand resulting from the temporary economic lockdown is a glimpse into a not-too-distant future where electrification could disrupt demand on a similar scale. According to BNP Parabas, “the economics of oil for gasoline and diesel vehicles versus wind- and solar-powered EVs are now in relentless and irreversible decline.” While the world will require tens of millions of barrels of oil per day for years to come, there is no avoiding the fact that we are living in an era of energy transformation.

Canada is home to a number of companies that already know the benefits of getting ahead of global market shifts. TransAlta Corp., a 109-year-old predominantly fossil-fuel power producer, ramped up its wind and hydro investments and spun these off into a separate company. TransAlta Renewables is now worth more than its parent.

Wind, solar and hydro aren’t the only options for diversifying. While still dwarfed by global crude markets, we know that there are potential multibillion-dollar markets close to the conventional energy industry that don’t involve combustion: bitumen-based carbon fibres and activated carbon, hydrogen, renewable jet-fuels and geothermal energy. On the broader natural resources front, Canada is a treasure trove of low carbon commodities the world needs to decarbonize, and we are producing those commodities in an increasingly low carbon manner.  Notably, Canada is one the top-five producers of important minerals for rapidly expanding battery markets, including nickel, cobalt and graphite (and soon lithium from Alberta’s oilfield brines could be added to that list). We have the resources and  industrial ecosystem to be a North American hub for battery production and zero emissions vehicles including freight trucks and buses. 

These markets will grow quickly, driven by policy and economics – and Canada has all the ingredients to be a supplier of choice.

Carbon fibre, activated carbon and hydrogen potential

Carbon fibres (CFs) and activated carbon may be the least well understood of these opportunities for the oil sands and the ones with the most disruptive potential.

Activated carbon (AC) is a form of carbon with small, low-volume pores that increase the surface area available for adsorption or chemical reactions. Due to its high degree of microporosity, one gram of activated carbon can have a surface area of 3,000 square metres. The high surface area provides many useful applications. Further chemical treatment often enhances adsorption properties.

Commercial application of AC includes methane and hydrogen storage, air purification, solvent recovery, decaffeination, gold purification, metal extraction, water purification, medicine, sewage treatment, air filters in gas masks and respirators, filters in compressed air and teeth whitening. Alberta Innovates has done a preliminary market analysis and assessed the potential of using bitumen to make AC.

For the period of 2017 to 2023, global demand for AC is expected to be 1.3 million metric tonnes. If 15% of this demand could be satisfied by oil sands, it would represent asphaltene (the stuff that makes the oil sands so viscous) and bitumen demands of 316,000 metric tonnes (at US$2,500 per tonne) and 36,000 barrels per day, respectively. If oil-sands-derived AC could capture 15% of the total global AC market by 2030, it would create asphaltene and bitumen requirements of 1.4 million metric tonnes and 160,000 barrels per day, respectively, generating $21 billion in annual revenue.

Composed mostly of carbon atoms, CFs possess unparallelled strength and stiffness (carbon fibre is five to 10 times stronger than steel and twice as stiff) coupled with low density (making it lighter than aluminum) and high resistance to corrosion. This makes the material particularly well suited for use in electric vehicles and aviation, and commercial polymers.

Currently, most commercial CFs are made from polyacrylonitrile (PAN), and a small fraction of commercial CFs are made from petroleum pitch, mostly outside of Canada. The supply chain for making carbon fibre from PAN spans three continents, with production costs starting at about US$18/kilogram (kg) for PAN-derived CFs. Demand at the current cost is about 100,000 tonnes per year. If costs were halved to US$9/kg, some experts believe that demand would increase tenfold based solely on automobile sector uptake, with Alberta Innovates estimating a potential $44 billion in annual revenue from CFs by 2030. (Canadian CF production on this scale could help Ontario become the lowest-cost manufacturer of lightweight frames for aviation, freight and personal vehicles.)

Canadian-made CF using Alberta bitumen could be the solution for low-cost carbon fibres. Asphaltene, which makes up 15 to 20% of bitumen, is a promising feedstock for making CFs and AC. If we can crack the cost nut of extracting CFs and AC from bitumen, it has the potential to deliver four times the revenue from Alberta’s current bitumen output. By diverting 30% of current oil sands activity to high-value advanced materials such as carbon fibre, activated carbon and asphalt binder, Alberta Innovates estimates the added economic potential could be in the range of $84 billion annually (including $19 billion from asphalt binder), while reducing GHG emissions from combustion by over 120 MT CO2 per year.

Materials companies such as BASF, Zoltek, Lafarge and Mitsubishi Chemicals, not surprisingly, have their eyes on CFs as a future market. Alberta Innovates is engaged with the Oak Ridge National Laboratory and three private sector partners on scaling up CF production from Alberta bitumen. One potential first application: CF hydrogen storage tanks.

Globally, Bloomberg New Energy Finance (BNEF) recently characterized hydrogen as a clean-burning molecule that could become a zero-carbon substitute for fossil fuels in hard-to-abate sectors of the economy, including as feedstock for heavy industry. The cost of producing hydrogen from renewable sources will continue to fall, but we need to ramp up demand to drive down costs and build out the delivery infrastructure. BNEF argues that this will not happen without government targets and subsidies that BNEF pegs at US$150 billion of cumulative subsidies globally by 2030. The goal of these policy investments would drive the delivered cost of hydrogen down to $15 per million British thermal units (MMBtu) in many parts of the world by 2030 and to $7.4/MMBtu by 2050.

In Canada, an industry collaboration project is already underway in Alberta. The Alberta Zero Emissions Truck Electrification Collaboration (AZETEC) project, a $15-million, three-year joint venture between Emissions Reduction Alberta, AZETEC and the private sector, is focused on building out the infrastructure that’s needed for a wider network of hydrogen fuelling stations for long-haul transportation. Trucks are the dominant mode of moving freight in Canada, and while the largest long-haul rigs make up only 9% of the freight truck population, they account for 47% of commercial truck fuel consumption. The AZETEC project is focused on the largest vehicles on our roads. While it is uncertain whether hydrogen or electricity will power heavy freight vehicles of the future, there’s a strong consensus that both technologies will have a role to play.

The prospect of producing zero-carbon, “green” hydrogen from renewable electricity where oil and gas are produced today is within our grasp. In our Building Back Better Power scenario, we envisioned a 10-year program of wind and solar development in Alberta and Saskatchewan, complemented by energy storage and enhanced transmission capacity both within the provinces and with their hydro-rich neighbours. The investment in Alberta alone would top $50 billion over the 10-year period and create more than 50,000 full-time jobs for the rest of the decade. The $5 billion per year average capital expenditure is of the same order as recent capital investments in Alberta’s energy sector (15 to $20 billion per year in oil and gas, $3.5 billion per year in utilities). The Travers Solar Project in Vulcan County, Alberta, which has received $500 million from a Danish group, is an indicator of the growing investor interest in the solar-rich resources of southern Alberta and Saskatchewan.

Geothermal potential

Canadian resources of geothermal energy – the heat found deep underground in hot aquifers and rocks – are concentrated in western Canada and can be harnessed for both power and heat for buildings. Exploratory drilling costs usually represent a major component of the cost of developing geothermal energy, but western Canada’s geothermal energy resources have been largely located as the result of oil and gas exploration and drilling. The expertise and technical know-how required for geothermal energy development already exists in the Canadian oil and gas industry and constitutes another strategic advantage, with both the supply chains and skilled human resources readily available. In addition to their potential for baseload power production, the Energy Futures Lab suggests that geothermal resources could be used to create new district heating systems for pulp- and paper-making and agriculture.

Aviation fuel potential 

A final example of a global market that may grow substantially is sustainable aviation fuel (SAF). The World Economic Forum’s report on the Net Zero Challenge puts the cost of abating a tonne of CO2 in the aviation industry at $200, compared to cement at $90 and steel at $130. Given that the COVID-19 pandemic has forced the global aviation industry to restructure at a unprecedented scale, it remains to be seen whether the industry will stick with carbon-reduction goals established under the Carbon Offsetting and Reduction Scheme for International Aviation (CORSIA). It’s worth noting, though, that under the International Energy Agency’s Sustainable Development Scenario, SAF is projected to grow to 18 billion litres by 2025 and 37 billion litres by 2030. Companies such as Finland’s Neste have made bold moves to diversify into sustainable biofuels and have already developed profitable niches serving airports such as Bergen, Oslo and Stockholm, three of only five airports globally that offer regular SAF distribution. In the past five years following Neste’s big bet on sustainable biofuels, its share price has more than tripled to bring its value up to C$40 billion, while the value of oil and gas peers has been cut in half.

Given the economic opportunity in moving beyond carbon and Canada’s commitment to reach net-zero by 2050, Building Back Better means that we need to harness the growing global markets for zero-carbon products and technologies as part of the transition away from producing oil and gas.

The proposal

In previous installments of this Building Back Better series, we have outlined the economic and job-creation potential in Canada from public and private sector investments in retrofitting buildings, decarbonizing the power grid, greening heavy industry, electrifying vehicles, promoting active transportation, and innovating nature-based climate mitigation solutions in forestry and agriculture. For the oil-producing provinces of Alberta, Saskatchewan and Newfoundland, these proposals include $200 billion in capital investments that generate 140,000 full-time jobs over the 10-year recovery program. All combined, the lion’s share of this activity would be in Alberta – $140 billion and 100,000 full-time jobs.

In addition, the federal government should create a $40 billion Natural Resources and EV Innovation Fund, which would be endowed through the issuance of sovereign green bonds, taking advantage of low borrowing rates.

Building on the lessons from AOSTRA, the Natural Resources and EV Innovation Fund would need:

1. Right goal: The goal of the fund should be rapid research, development and deployment to de-risk breakthrough technologies and to produce zero-carbon commodities, batteries and EVs on a commercial scale to sell into growing global markets where Canada has a competitive advantage. Opportunity areas include bitumen-based carbon fibre and activated carbon as well as green hydrogen, geothermal heat loops and sustainable aviation fuels. Assuming moderate levels of follow-on investment by the private sector to deploy the new technologies to produce the zero-carbon commodities (financed via debt capital markets for which the federal government could offer public incentives), it’s estimated that investment in these sectors on this scale would create up to 100,000 permanent high quality jobs over the next 10 years.

2. Right structure: The fund will be independently delivered by an organization with strong technical capacity, with government setting goals that prioritize public benefit over the long-term with two buckets: one for R&D and one for commercial deployment. As with AOSTRA, the ownership of intellectual property (IP) should remain in public hands so that it will be widely used for the benefit of all Canadians. Organizations with the technical expertise to deliver on this mandate include Alberta Innovates and Emissions Reduction Alberta. And unlike AOSTRA, which was strictly an R&D vehicle, the fund would have a mandate (in an expanded and revamped version of the Strategic Innovation Fund, or possibly as a new sleeve within the Canadian Infrastructure Bank) to make direct investments to deploy these commercial technologies and would take minority equity stakes in exchange for these direct investments. Two important things to note:

• AOSTRA made their investment over 30 years and then hit the exit after they had proven the viability of SAGD (steam-assisted gravity drainage) technology in extracting bitumen from underground oil sands deposits. Given the realities of today’s strained provincial and corporate balance sheets, the pace of change in global energy markets, and the scale of the incumbent industry (which makes the stakes higher for getting it right), we are looking at a compressed time scale that requires more investment in less time.
• It is important to get IP protection right. We can invest a lot of money and develop successful technologies, but we may lose out on benefits if we lose control of IP. The government will need to fund 100% cash for R&D up to the point of deployment in order to own IP for any research that involves non-Canadian entities. Industry co-investment may give partners usage rights but not IP ownership.

3. Right scale: A 10-year investment by the federal government of $40 billion ($5 billion for R&D and $35 billion to deploy and crowd in private sector investment), with the objective of securing triple that amount from the private sector and support from provinces as per their capacity. The fund would be fully endowed to insulate it from changing political priorities and to take advantage of low interest rates.

While drawing lessons from AOSTRA, we also need to be mindful that 2020 is not the 1970s in two important respects:

• The scale of human capital and infrastructure for Canadian innovation today is much greater than in 1974, when AOSTRA was established.
• In response to post-pandemic recovery needs, the federal government is poised to make large-scale (once-in-a-generation levels) public investment over the coming years to help Canada build back better.

We have a lot more to lose if we don’t invest wisely now to create an economic engine for the future. At the same time, the current moment offers an opportunity to act quickly and place Canada in a leadership position in fast-growing global markets.

We estimate that the prize for getting this right is being the supplier of choice for $125 billion zero-carbon commodities per year by 2030, while creating 1,000,000 person years of employment.

To paraphrase the philosopher George Santayana, those who learn from the past are empowered to win the future.

Ralph Torrie is senior associate with Sustainability Solutions Group and partner at Torrie Smith Associates.

Céline Bak is the founder and president of Analytica Advisors.

Toby Heaps is the CEO and co-founder of Corporate Knights. 

With files from Aleena Naseem and Laura Väyrynen

Notice to reader: Please be aware some of the figures and other details in this white paper have been updated in the Final Report to reflect feedback.

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What distinguishes this brownfield project isn’t just the size (which happens to be roughly the same as Edmonton’s current downtown). When it’s completed, it will be one of the largest purpose-built sustainable communities in the world, according to municipal officials.

The City of Edmonton, acting as the developer, is rolling out an ambitious low-carbon development strategy that will produce a denser, greener, bike- and pedestrian-friendly community that will feature its own district energy utility, two LRT stops and dwellings built to demanding green-building-code standards. And in a city prone to flooding, the replacement of acres of tarmac with new permeable green spaces (including an 80-acre park) will provide additional benefit. Once complete, Blatchford is expected to be home to 30,000 people (with “homes for all stages of life,” including affordable housing), as well as offices and retail shops in a walkable town centre.

Christian Felske, the city official in charge of Blatchford’s renewable energy portfolio, says the district is designed to be completely carbon neutral. Its energy will be entirely renewable, produced by a combination of solar, sewer heat recovery and geothermal heat, all of it built atop a smart grid. A typical Blatchford townhouse – the largest available dwelling unit – will use about a third of the energy consumed by comparably sized homes elsewhere in Edmonton.

The district energy utility, which will be owned by the city, will distribute heating and cooling to structures connected to a geothermal pipe network. It will become not only the largest such installation in Canada but a way of showcasing the local geothermal sector.

The design has previously attracted controversy as some geothermal experts criticized the techniques employed by the contractor installing the system. But Felske says they’ve taken a “very staged and prudent approach in terms of delivering the site.”

In later phases, Blatchford will also include systems that recover waste heat from sewers. Adds Felske, “As the land development grows, the utility will grow.”

Toronto journalist John Lorinc writes about cities, sustainability and business.

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One area where life has improved relates to gender and ethnic diversity in the corporate world. Mariette DiChristina, editor-in-chief of Scientific American, weighed into the issue in a commentary for Huffington Post, where she cited research supporting the benefits of diversity. For example, companies in Standard & Poor’s Composite 1500 index that have women in senior management have been shown to be worth an average of $42 million more than companies with only men in management, and these same companies have a higher “innovation intensity” score. “When a team is trying to do something new that requires knowledge and experience surpassing what any one member can supply, a more challenging social situation leads to better outcomes,” DiChristina writes. “When we have to try harder to communicate with collaborators who are different from us, we better articulate our ideas.”

The International Organization for Standardization, otherwise known as the ISO, is in the process of revamping its greenhouse-gas standards “in response to climate change needs.” The standards were first published in 2006, and have become essential tools for organizations and programs that track and work to reduce GHG emissions. They are also relied on for emissions trading. But the world has changed significantly over the past nine years, so the ISO’s Technical Committee will be reviewing better ways to quantify and report emissions and make sure new market needs are addressed.

In Canada, a new report from the Canadian Geothermal Energy Association has found that British Columbia alone has “sufficient developable resource to meet the entire province’s power demands.” The most conservative estimate, according to the report, is that B.C. has a technical potential of between 5,500 and 6,600 megawatts of geothermal power resources, an amount considered achievable using current technology at relatively shallow depths (up to 2,500 metres deep). The data this estimate is based on, however, only covers 23 per cent of the province’s territory. Outside of that area, composed largely of volcanic and crystalline rock, there is even greater potential. “As such, an estimate of British Columbia’s full technical potential should be multiples of that.”

And Ontario finally launched its inaugural green bond this week, a first for a government in Canada, after announcing its intention to do so last month. The bonds have a four-year term, and while the issue was set at $500 million there were reportedly $2.5 billion in orders from over 80 investors, according to the Financial Post. Proceeds will be used for projects that carry defined environmental benefits. Sustainable transportation, clean energy, sustainable land management and climate adaption are some of the eligible project themes. Bank of America Merrill Lynch, CIBC World Markets, HSBC Securities and RBC Capital Markets joint-led management of the offering, which closes next week.

To date there have been nearly $30 billion worth of green bond issues worldwide in 2014, on track to achieve an estimated $40 billion by year-end, according to the Climate Bonds Initiative, which advocates for green bonds and tracks the market. In most cases, as in Ontario, green bond issues have been over-subscribed.

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