Results of Two-Year FIT Review Announced

Belarus Nuclear Power Infrastructure Review evaluates IAEA INIR Phase 3 readiness at Ostrovets NPP, VVER-1200 reactors, legal and regulatory framework, commissioning, safety, emergency preparedness, and energy diversification in a low-carbon program.

Key Points

An IAEA INIR Phase 3 assessment of Belarus readiness to commission and operate the Ostrovets NPP with VVER-1200 units.

✅ Reviews legal, regulatory, and institutional arrangements

✅ Confirms Phase 3 readiness for safe commissioning and operation

✅ Highlights good practices in peer reviews and emergency planning

An International Atomic Energy Agency (IAEA) team of experts today concluded a 12-day mission to Belarus to review its infrastructure development for a nuclear power programme. The Integrated Nuclear Infrastructure Review (INIR) was carried out at the invitation of the Government of Belarus.

Belarus, seeking to diversify its energy production with a reliable low-carbon source, and aware of the benefits of energy storage for grid flexibility, is building its first nuclear power plant (NPP) at the Ostrovets site, about 130 km north-west of the capital Minsk. The country has engaged with the Russian Federation to construct and commission two VVER-1200 pressurised water reactors at this site and expects the first unit to be connected to the grid this year.

The INIR mission reviewed the status of nuclear infrastructure development using the Phase 3 conditions of the IAEA’s Milestones Approach. The Ministry of Energy of Belarus hosted the mission.

The INIR team said Belarus is close to completing the required nuclear power infrastructure for starting the operation of its first NPP. The team made recommendations and suggestions aimed at assisting Belarus in making further progress in its readiness to commission and operate it, including planning for integration with variable renewables, as advances in new wind turbines are being deployed elsewhere to strengthen the overall energy mix.

“This mission marks an important step for Belarus in its preparations for the introduction of nuclear power,” said team leader Milko Kovachev, Head of the IAEA’s Nuclear Infrastructure Development Section. “We met well-prepared, motivated and competent professionals ready to openly discuss all infrastructure issues. The team saw a clear drive to meet the objectives of the programme and deliver benefits to the Belarusian people, such as supporting the country’s economic development, including growth in EV battery manufacturing sectors.”

The team comprised one expert from Algeria and two experts from the United Kingdom, as well as seven IAEA staff. It reviewed the status of 19 nuclear infrastructure issues using the IAEA evaluation methodology for Phase 3 of the Milestones Approach, noting that regional integration via an electricity highway can shape planning assumptions as well. It was the second INIR mission to Belarus, who hosted a mission covering Phases 1 and 2 in 2012.

Prior to the latest mission, Belarus prepared a Self-Evaluation Report covering all infrastructure issues and submitted the report and supporting documents to the IAEA.

The team highlighted areas where further actions would benefit Belarus, including the need to improve institutional arrangements and the legal and regulatory framework, drawing on international examples of streamlined licensing for advanced reactors to ensure a stable and predictable environment for the programme; and to finalize the remaining arrangements needed for sustainable operation of the nuclear power plant.

The team also identified good practices that would benefit other countries developing nuclear power in the areas of programme and project coordination, the use of independent peer reviews, cooperation with regulators from other countries, engagement with international stakeholders and emergency preparedness, and awareness of regional initiatives such as new electricity interconnectors that can enhance system resilience.

Mikhail Chudakov, IAEA Deputy Director General and Head of the Department of Nuclear Energy attended the Mission’s closing meeting. “Developing the infrastructure required for a nuclear power programme requires significant financial and human resources, and long lead times for preparation and the approval of major transmission projects that support clean power flows, and the construction activities,” he said. “Belarus has made commendable progress since the decision to launch a nuclear power programme 10 years ago.”

“Hosting the INIR mission, Belarus demonstrated its transparency and genuine interest to receive an objective professional assessment of the readiness of its nuclear power infrastructure for the commissioning of the country’s first nuclear power plant,” said Mikhail Mikhadyuk, Deputy Minister of Energy of the Republic of Belarus. ”The recommendations and suggestions we received will be an important guidance for our continuous efforts aimed at ensuring the highest level of safety and reliability of the Belarusian NPP."
 

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Rising Electricity Prices are driven by inflation, climate change, and the clean energy transition, affecting energy bills, grid resilience, and supply. Renewables, storage, and infrastructure upgrades shape costs, volatility, and long-term sustainability.

Key Points

Rising electricity prices stem from inflation, climate risk, and costs of integrating clean energy and storage into modern grids.

✅ Inflation raises fuel, materials, and labor costs for utilities

✅ Extreme weather damages infrastructure and strains peak demand

✅ Clean energy rollout needs storage, backup, and grid upgrades

In recent months, consumers have been grappling with a concerning trend: rising electricity prices across the country. This increase is not merely a fluctuation but a complex issue shaped by a confluence of factors including inflation, climate change, and the transition to clean energy. Understanding these dynamics is crucial for navigating the current energy landscape and preparing for its future.

Inflation and Its Impact on Energy Costs

Inflation, the economic phenomenon of rising prices across various sectors, has significantly impacted the cost of living, including electricity and natural gas prices for households. As the price of goods and services increases, so too does the cost of producing and delivering electricity. Energy production relies heavily on raw materials, such as metals and fuels, whose prices have surged in recent years. For instance, the costs associated with mining, transporting, and refining these materials have risen, thereby increasing the operational expenses for power plants.

Moreover, inflation affects labor costs, as wages often need to keep pace with the rising cost of living. As utility companies face higher expenses for both materials and labor, these costs are inevitably passed on to consumers in the form of higher electricity bills.

Climate Change and Energy Supply Disruptions

Climate change also plays a significant role in driving up electricity prices. Extreme weather events, such as hurricanes, heatwaves, and floods, have become more frequent and severe due to climate change. These events disrupt energy production and distribution by damaging infrastructure, impeding transportation, and affecting the availability of resources.

For example, hurricanes can knock out power plants and damage transmission lines, leading to shortages and higher costs. During periods of extreme summer heat across many regions, heatwaves can strain the power grid as increased demand for air conditioning pushes the system to its limits. Such disruptions not only lead to higher immediate costs but also necessitate costly repairs and infrastructure upgrades.

Additionally, the increasing frequency of natural disasters forces utilities to invest in more resilient infrastructure, as many utilities spend more on delivery to harden grids and reduce outages, which adds to overall costs. These investments, while necessary for long-term reliability, contribute to short-term price increases for consumers.

The Transition to Clean Energy

The shift towards clean energy is another pivotal factor influencing electricity prices. While renewable energy sources like wind, solar, and hydro power are crucial for reducing greenhouse gas emissions and combating climate change, their integration into the existing grid presents challenges.

Renewable energy infrastructure requires substantial initial investment. The construction of wind farms, solar panels, and the associated grid improvements involve significant capital expenditure. These upfront costs are often reflected in electricity prices. Moreover, renewable energy sources can be intermittent, meaning they do not always produce electricity at times of high demand. This intermittency necessitates the development of energy storage solutions and backup systems, which further adds to the costs.

Utilities are also transitioning from fossil fuel-based energy production to cleaner alternatives, a process that involves both technological and operational shifts and intersects with the broader energy crisis impacts on electricity, gas, and EVs nationwide. These changes can temporarily increase costs as utilities phase out old systems and implement new ones. While the long-term benefits of cleaner energy include environmental sustainability and potentially lower operating costs, the transition period can be financially burdensome for consumers.

The Path Forward

Addressing rising electricity prices requires a multifaceted approach. Policymakers must balance the need for immediate relief, as California regulators face calls for action amid soaring bills, with the long-term goals of sustainability and resilience. Investments in energy efficiency can help reduce overall demand and ease pressure on the grid. Expanding and modernizing energy infrastructure to accommodate renewable sources can also mitigate price volatility.

Additionally, efforts to mitigate climate change through improved resilience and adaptive measures can reduce the frequency and impact of extreme weather events, thereby stabilizing energy costs.

Consumer education is vital in this process. Understanding the factors driving electricity prices can empower individuals to make informed decisions about energy consumption and conservation. Furthermore, exploring energy-efficient appliances and practices can help manage costs in the face of rising prices.

In summary, the rising cost of electricity is a multifaceted issue influenced by inflation, climate change, and the transition to clean energy, and recent developments show Germany's rising energy costs in the coming year. While these factors pose significant challenges, they also offer opportunities for innovation and improvement in how we produce, distribute, and consume energy. By addressing these issues with a balanced approach, it is possible to navigate the complexities of rising electricity prices while working towards a more sustainable and resilient energy future.

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Germany net-zero roadmap charts coal phase-out by 2030, rapid renewables buildout, energy storage, and hydrogen-ready gas engines to cut emissions and lower LCOE by 34%, unlocking a resilient, flexible, low-cost power system by 2040.

Key Points

Plan to phase out coal by 2030 and gas by 2040, scaling renewables, storage, and hydrogen to cut LCOE and emissions.

✅ Coal out by 2030; gas phased 2040 with hydrogen-ready engines

✅ Add 19 GW/yr renewables; 30 GW storage by 2040

✅ 34% lower LCOE, 23% fewer emissions vs slower path

Germany can achieve significant reductions in emissions and the cost of electricity by phasing out coal in 2030 under its coal phase-out plan but must have a clear plan to ramp up renewables and pivot to sustainable fuels in order to achieve net-zero, according to a new whitepaper from Wartsila.

The modelling, published in Wärtsilä new white paper ‘Achieving net-zero power system in Germany by 2040’, compares the current plan to phase out coal by 2030 and gas by 2045 with an accelerated plan, where gas is phased out by 2040. By accelerating the path to net-zero, Germany can unlock a 34% reduction in the levelised cost of energy, as well as a 23% reduction in the total emissions, or 562 million tonnes of carbon dioxide in real terms.

The modelling offers a clear, three-step roadmap to achieve net-zero: rapidly increase renewables, energy storage and begin future-proofing gas engines in this decade; phase out coal by 2030; and phase out gas by 2040, converting remaining engines to run on sustainable fuels.

The greatest rewards are available if Germany front-loads decarbonisation. This can be done by rapidly increasing renewable capacity, adding 19 GW of wind and solar PV capacity per year. It must also add a total of 30GW of energy storage by 2040.

Håkan Agnevall, President and CEO of Wärtsilä Corporation said: “Germany stands on the precipice of a new, sustainable energy era. The new Federal Government has indicated its plans to consign coal to history by 2030. However, this is only step one. Our white paper demonstrates the need to implement a three-step roadmap to achieve net-zero. It is time to put a deadline on fossil fuels and create a clear plan to transition to sustainable fuels.”

While a rapid coal phase-out has been at the centre of recent climate policy debates, including the ongoing nuclear debate over Germany’s energy mix, the pathway to net-zero is less clear. Wärtsilä’s modelling shows that gas engines should be used to accelerate the transition by providing a short-term bridge to enable net zero and navigate the energy transition while balancing the intermittency of renewables until sustainable fuels are available at scale.

However, if Germany follows the slower pathway and reaches net-zero by 2045, it risks becoming reliant on gas as baseload power for much of the 2030s amid renewable expansion challenges that persist, potentially harming its ability to reach its climate goals. 

Creating the infrastructure to pivot to sustainable fuels is one of the greatest challenges facing the German system. The ability to convert existing capacity to run purely on hydrogen via hydrogen-ready power plants will be key to reaching net-zero by 2040 and unlocking the significant system-wide benefits on offer.

Jan Andersson, General Manager of Market Development in Germany, Wärtsilä Energy added: “To reach the 2040 target and unlock the greatest benefits, the most important thing that Germany can do is build renewables now. 19 GW is an ambitious target, but Germany can do it. History shows us that Germany has been able to achieve high levels of renewable buildout in previous years. It must now reach those levels consistently.

“Creating a clear plan which sets out the steps to net zero is essential. Renewable energy is inherently intermittent, so flexible energy capacity will play a vital role. While batteries provide effective short-term flexibility, gas is currently the only practical long-term option. If Germany is to unlock the greatest benefits from decarbonisation, it must have a clear plan to integrate sustainable fuel. From 2030, all new thermal capacity must run solely on hydrogen.”

Analysis of the last decade demonstrates that the rapid expansion of renewable energy is possible, and that renewables overtook coal and nuclear in generation. Previously, Germany has built large amounts of renewable capacity, including 8GW of solar PV in 2010 and 2011, 5.3 GW of onshore wind in 2017, and 2.5 GW of offshore wind in 2015.

The significant reductions in the cost of electricity demonstrated in the modelling are driven by the fact that renewables are far cheaper to run than coal or gas plants, even as coal still provides about a third of electricity in Germany. The initial capital investment is far outweighed by the ongoing operational expense of fossil fuel-based power.

As well as reducing emissions and costs, Germany’s rapid path to net-zero can also unlock a series of additional benefits. If coal is phased out by 2030 but capacity is not replaced by high levels of renewable energy, Germany risks becoming a significant energy importer, peaking at 162 TWh in 2035. The accelerated pathway would reduce imports by a third.

Likewise, more renewable energy will help to electrify district heating, meaning Germany can move away from carbon-intensive fuels sooner. If Germany follows the accelerated path, 57% of Germany’s heating could be electrified in 2045, compared to 10% under the slower plan.

Jan Andersson concluded: “The opportunities on offer are vast. Germany can provide the blueprint for net zero and galvanise an entire continent. Now is the time for the new government to seize the initiative.”

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Electric Field-Induced Glass Softening reveals a Joule heating anomaly in silicate glass, where anode-side nanoscale alkali depletion drives ionic conduction, localized thermal runaway, melting, and evaporation, challenging homogeneity assumptions and refining materials processing models.

Key Points

An effect where electric fields lower glass softening temperature via nanoscale ionic migration and structural change.

✅ Anode-side alkali depletion creates extreme, localized heating

✅ Thermal runaway melts glass near the anode despite uniform bulk

✅ Findings refine Joule heating models and enable new glass processing

A team of scientists working with electrical currents and silicate glass have been left gobsmacked after the glass appeared to defy a basic physical law, in a field that also explores electricity-from-air devices for novel energy harvesting.

If you pass an electrical current through a material, the way that current generates heat can be described by Joule's first law. It's been observed time and time again, with the temperature always evenly distributed when the material is homogeneous (or uniform).

But not in this recent experiment. A section - and only a section - of silicate glass became so hot that it melted, and even evaporated. Moreover, it did so at a much lower temperature than the boiling point of the material.

The boiling point of pure silicate glass is 2,230 degrees Celsius (4,046 degrees Fahrenheit). The hottest temperature the researchers recorded in a homogeneous piece of silicate glass during the experiment was 1,868.7 degrees Celsius.

Say whaaaat.

"The calculations did not add up to explain what we were seeing as simply standard Joule heating," said engineer and materials scientist Himanshu Jain of Lehigh University.

"Even under very moderate conditions, we observed fumes of glass that would require thousands of degrees higher temperature than Joule's law could predict!"

Jain and his colleagues from materials science company Corning Incorporated were investigating a phenomenon they had described in a previous paper. In 2015, they reported that an electric field could reduce the temperature at which glass softens, by as much as a few hundred degrees, a line of inquiry that parallels work on low-cost heat-to-electricity materials in energy research. They called this "electric field-induced softening."

It was certainly a peculiar phenomenon, so they set up another experiment. They put pieces of glass in a furnace, and applied 100 to 200 volts in the form of both alternating and direct currents.

Next, a thin wisp of vapour emanated from the spot where the anode conveying the current contacted the glass.

"In our experiments, the glass became more than a thousand degrees Celsius hotter near the positive side than in the rest of the glass, which was very surprising considering that the glass was totally homogeneous to begin with," Jain said.

This seems to fly in the face of Joule's first law, so the team investigated more closely - and found that the glass wasn't remaining as homogeneous as it started out. The electric field changed the chemistry and the structure of the glass on nanoscale, in just a small section close to the anode.

This region heats faster than the rest of the glass, to the point of becoming a thermal runaway - where an increase in temperature further increases temperature in a blistering feedback loop.

As it turned out, that spot of structural change and dramatic heat resulted in a small area of glass reaching melting point while the rest of the material remained solid.

"Unlike electronically conducting metals and semiconductors, with time the heating of ionically conducting glass becomes extremely inhomogeneous with the formation of a nanoscale alkali-depletion region, such that the glass melts near the anode, even evaporates, while remaining solid elsewhere," the researchers wrote in their paper.

In other words, the material wasn't homogeneous any more, which means the glass heating experiment doesn't exactly change how we apply Joule's first law.

But it's an exciting result, since until now we didn't know a material could actually lose its homogeneity with the application of an electrical current, with possible implications for thin-film heat harvesters in electronics. (The thing is, no one had tried electrically heating glass to these extreme temperatures before.)

So the physical laws of the Universe are still okay, as a piece of glass hasn't broken them. But Joule's first law may need a bit of tweaking to take this effect into account, a reminder that unconventional energy concepts like nighttime solar cells also challenge our intuitions.

And, of course, it's another piece of understanding that could help us in other ways too, including advances in thermoelectric materials that turn waste heat into electricity.

"Besides demonstrating the need to qualify Joule's law," Jain said, "the results are critical to developing new technology for the fabrication and manufacturing of glass and ceramic materials."

The research has been published in Scientific Reports.

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Ontario Clean Energy Expansion signals IESO-backed renewables, energy storage, and low-CO2 power to meet EV-driven demand, offset Pickering nuclear retirement, and balance interim gas-fired generation while advancing grid reliability, decarbonization, and net-zero targets.

Key Points

Ontario Clean Energy Expansion plans to grow renewables and storage, manage short-term gas, and meet rising demand.

✅ IESO long-term procurements for renewables and storage

✅ Interim reliance on gas to replace Pickering capacity

✅ Targets align with net-zero grid reliability goals

After cancelling hundreds of renewable power projects four years ago, the Doug Ford government appears set to expand clean energy to meet a looming electricity shortfall across the province.

Recent announcements from Ontario Energy Minister Todd Smith and the province’s electric grid management agency suggest the province plans to expand low-CO2 electricity with new wind and solar plans in the long-term, even as it ramps up gas-fired power over the next five years.

The moves are in response to an impending electricity shortfall as climate-conscious drivers switch to electric vehicles, farmers replace field crops with greenhouses and companies like ArcelorMittal Dofasco in Hamilton switch from CO2-heavy manufacturing to electricity-based production. Forecasters predict Canada will need to double its power supply by 2050.

While Ontario has a relatively low-CO2 power system, the province’s electricity supply will be reduced in 2025 when Ontario Power Generation closes the 50-year-old Pickering nuclear station, now near the end of its operating life. This will remove 3,100 megawatts of low-CO2 generation, about eight per cent of the province’s 40,000-megawatt total.

The impending closure has created a difficult situation for the Independent Electricity System Operator (IESO), the provincial agency managing Ontario’s grid. Last year, it forecasted it would need to sharply increase CO2-polluting natural gas-fired power to avoid widespread blackouts.

This would mean drivers switching to electric vehicles or companies like Dofasco cutting CO2 through electrification would end up causing higher power system emissions.

It would also fly in the face of the federal government’s ambition to create a net-zero national electricity system by 2035, a critical part of Canada’s pledge to reduce CO2 emissions to zero by 2050.

Yet the Ford government has appeared reluctant to expand clean energy. In the 2018 election, clean electricity was a key issue as it appealed to anti-turbine voters in rural Ontario and cancelled more than 700 renewable energy contracts shortly after taking office, taking 400 megawatts out of the system.

But there are signs the government is having a change of heart. IESO recently released a list of 55 companies approved to submit bids for 3,500 megawatts of long-term electricity contracts starting between 2025 and 2027, and the energy minister has outlined a plan to address growing energy needs as well.

The companies include a variety of potential producers, ranging from Canadian and global renewable companies to local utilities and small startups. Most are renewable power or energy storage companies specializing in low- or zero-emission power. IESO plans additional long-term bid offerings in the future.

This doesn’t mean gas generation will be turned off. IESO will contract yearly production from existing gas plants until 2028 (the annual contract in 2023 will be for about 2,000 megawatts). As well, IESO has issued contracts to four gas-fired producers, a small wind company and a storage company to begin production of about 700 megawatts to boost gas plant output starting between 2024 and 2026.

While this represents an expansion of existing gas-fired generation, Smith has asked IESO to report on a gas moratorium, saying he doesn’t believe new gas plants will be needed over the long term.

The NDP and Greens criticized the government for relying on gas in the near term. But clean energy advocates greeted the long-term plans positively.

The IESO process “will contribute to a clean, reliable and affordable grid,” said the Canadian Renewable Energy Association.

Rachel Doran, director of policy and strategy at Clean Energy Canada, said in an email the potential gas generation moratorium “is an encouraging step forward,” although she criticized the “unfortunate decision to replace near-term nuclear power capacity with climate-change-causing natural gas.”

There will have to be a massive clean energy expansion to green Ontario’s grid well beyond what has been announced in recent days for Ontario to meet its future energy needs (think a doubling of Ontario’s current 40,000-megawatt capacity by 2050).

But these first steps hold promise that Ontario is at least starting on the path to that goal, rather than scrambling to keep the lights on with CO2-polluting natural gas.

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Alberta Hydropower Potential highlights renewable energy, dams, reservoirs, grid flexibility, contrasting wind and solar growth with limited investment, regulatory hurdles, river basin resources, and decarbonization pathways across Athabasca, Peace, and Slave River systems.

Key Points

It is the technical capacity for new hydro in Alberta's river basins to support a more reliable, lower carbon grid.

✅ 42,000 GWh per year developable hydro identified in studies.

✅ Major potential in Athabasca, Peace, and Slave River basins.

✅ Barriers include high capital costs, market design, water rights.

When you think about renewable energy sources on the Prairies, your mind may go to the wind farms in southern Alberta, or even the Travers Solar Project, southeast of Calgary.

Most of the conversation around renewable energy in the province is dominated by advancements in solar and wind power, amid Alberta's renewable energy surge that continues to attract attention. 

But what about Canada's main source of electricity — hydro power?

More than half of Canada's electricity is generated from hydro sources, with 632.2 terawatt-hours produced as of 2019. That makes it the fourth largest installed capacity of hydropower in the world. 

But in Alberta, it's a different story. 

Currently, hydro power contributes between three and five per cent of Alberta's energy mix, while fossil fuels make up about 89 per cent.

According to Canada's Energy Future report from the Canada Energy Regulator, by 2050 it will make up two per cent of the province's electricity generation shares.

So why is it that a province so rich in mountains and rivers has so little hydro power?

Hydro's history in Alberta
Hydro power didn't always make up such a small sliver of Alberta's electricity generation. Hydro installations began in the early 20th century as the province's population exploded. 

Grant Berg looks after engineering for hydro for TransAlta, Alberta's largest producer of hydro power with 17 facilities across the province.

"Our first plant was Horseshoe, which started in 1911 that we formed as Calgary Power," he said. 

"It was really in response to the City of Calgary growing and having some power needs."

Berg said in 1913, TransAlta's second installation, the Kananaskis Plant, started as Calgary continued to grow.

A historical photo of a hydro-electric dam in Kananaskis Alta. taken in 1914.
Hydro power plant in Kananaskis as seen in 1914. (Glenbow Archives)
Some bigger installations were built in the 1920s, including Ghost reservoir, but by mid-century population growth increased.

"Quite a large build out really, I think in response to the growth in Alberta following the war. So through the 1950s really quite a large build out of hydro from there."

By the 1950s, around half of the province's installed capacity was hydro power.

"Definitely Calgary power was all hydro until the 1950s," said Berg. 

Hydro potential in the province 
Despite the current low numbers in hydroelectricity, Alberta does have potential. 

According to a 2010 study, there is approximately 42,000 gigawatt-hours per year of remaining developable hydroelectric energy potential at identified sites. 

An average home in Alberta uses around 7,200 kilowatt-hours of electricity per year, meaning that the hydro potential could power 5.8 million homes each year. 

"This volume of energy could be sufficient to serve a significant amount of Alberta's load and therefore play a meaningful role in the decarbonization of the province's electric system," the Alberta Electric System Operator said in its 2022 Pathways to Net-Zero Emissions report.

Much of that potential lies in northern Alberta, in the Athabasca, Peace and Slave River basins.

The AESO report says that despite the large resource potential, Alberta's energy-only market framework has attracted limited investment in hydroelectric generation. 

Hydro power was once a big deal in Alberta, but investment in the industry has been in decline since the 1950s. Climate change reporter Christy Climenhaga explains why.
So why does Alberta leave out such a large resource potential on the path to net zero?

The government of Alberta responded to that question in a statement. 

"Hydro facilities, particularly large scale ones involving dams, are associated with high costs and logistical demands," said the Ministry of Affordability and Utilities. 

"Downstream water rights for other uses, such as irrigation, further complicate the development of hydro projects."

The ministry went on to say that wind and solar projects have increased far more rapidly because they can be developed at relatively lower cost and shorter timelines, and with fewer logistical demands.

"Sources from wind power and solar are increasingly more competitive," said Jean-Denis Charlebois, chief economist with the Canadian Energy Regulator. 

Hydro on the path to net zero
Hydro power is incredibly important to Canada's grid, and will remain so, despite growth in wind and solar power across the province.

Charlebois said that across Canada, the energy make-up will depend on the province. 

"Canadian provinces will generate electricity in very different ways from coast to coast. The major drivers are essentially geography," he said. 

Charlebois says that in British Columbia, Manitoba, Quebec and Newfoundland and Labrador, hydropower generation will continue to make up the majority of the grid.

"In Alberta and Saskatchewan, we see a fair bit of potential for wind and solar expansion in the region, which is not necessarily the case on Canada's coastlines," he said.

And although hydro is renewable, it does bring its adverse effects to the environment — land use changes, changes in flow patterns, fish populations and ecosystems, which will have to be continually monitored. 

"You want to be able to manage downstream effects; make sure that you're doing all the proper things for the environment," said Ryan Braden, director of mining and hydro at TransAlta.

Braden said hydro power still has a part to play in Alberta, even with its smaller contributions to the future grid. 

"It's one of those things that, you know, the wind doesn't blow or the sun doesn't shine, this is here. The way we manage it, we can really support that supply and demand," he said.

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