Indian power sector focuses on rural projects

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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Washington EV Rebate Program drives EV adoption with incentives, funding, and clean energy goals, cutting greenhouse gas emissions. Residents embrace electric vehicles as charging infrastructure expands, supporting sustainable transportation and state climate targets.

Key Points

Washington EV Rebate Program provides incentives to cut EV costs, accelerate adoption, and support clean energy targets.

✅ Over half of allocated funding already utilized statewide.

✅ Incentives lower upfront costs and spur EV demand.

✅ Charging infrastructure expansion remains a key priority.

Washington State has reached a significant milestone in its electric vehicle (EV) rebate program, with more than half of the allocated funding already utilized. This rapid uptake highlights the growing interest in electric vehicles as residents seek more sustainable transportation options. As the state continues to prioritize environmental initiatives, this development showcases both the successes and challenges of promoting electric vehicle adoption.

A Growing Demand for Electric Vehicles

The substantial drawdown of rebate funds indicates a robust demand for electric vehicles in Washington. As consumers become increasingly aware of the environmental benefits associated with EVs—such as reduced greenhouse gas emissions and improved air quality—more individuals are making the switch from traditional gasoline-powered vehicles. Additionally, rising fuel prices and advancements in EV technology, alongside zero-emission incentives are further incentivizing this shift.

Washington's rebate program, which offers financial incentives to residents who purchase or lease eligible electric vehicles, plays a critical role in making EVs more accessible. The program helps to lower the upfront costs associated with purchasing electric vehicles, and similar approaches like New Brunswick EV rebates illustrate how regional incentives can boost adoption, thus encouraging more drivers to consider these greener alternatives. As the state moves toward its goal of a more sustainable transportation system, the popularity of the rebate program is a promising sign.

The Impact of Funding Utilization

With over half of the rebate funding already used, the program's popularity raises questions about the sustainability of its financial support and the readiness of state power grids to accommodate rising EV demand. Originally designed to spur adoption and reduce barriers to entry for potential EV buyers, the rapid depletion of funds could lead to future challenges in maintaining the program’s momentum.

The Washington State Department of Ecology, which oversees the rebate program, will need to assess the current funding levels and consider future allocations to meet the ongoing demand. If the funds run dry, it could slow down the adoption of electric vehicles, potentially impacting the state’s broader climate goals. Ensuring a consistent flow of funding will be essential for keeping the program viable and continuing to promote EV usage.

Environmental Benefits and Climate Goals

The increasing adoption of electric vehicles aligns with Washington’s ambitious climate goals, including a commitment to reduce carbon emissions significantly by 2030. The state aims to transition to a clean energy economy and has set a target for all new vehicles sold by 2035 to be electric, and initiatives such as the hybrid-electric ferry upgrade demonstrate progress across the transportation sector. The success of the rebate program is a crucial step in achieving these objectives.

As more residents switch to EVs, the overall impact on air quality and carbon emissions can be profound. Electric vehicles produce zero tailpipe emissions, which contributes to improved air quality, particularly in urban areas that struggle with pollution. The transition to electric vehicles can also help to reduce dependence on fossil fuels, further enhancing the state’s sustainability efforts.

Challenges Ahead

While the current uptake of the rebate program is encouraging, there are challenges that need to be addressed. One significant issue is the availability of EV models. Although the market is expanding, not all consumers have equal access to a variety of electric vehicle options. Affordability remains a barrier for many potential buyers, especially in lower-income communities, but targeted supports like EV charger rebates in B.C. can ease costs for households. Ensuring that all residents can access EVs and the associated incentives is vital for equitable participation in the transition to electric mobility.

Additionally, there are concerns about charging infrastructure. For many potential EV owners, the lack of accessible charging stations can deter them from making the switch. Expanding charging networks, particularly in underserved areas, is essential for supporting the growing number of electric vehicles on the road, and B.C. EV charging expansion offers a regional model for scaling access.

Looking to the Future

As Washington continues to advance its electric vehicle initiatives, the success of the rebate program is a promising indication of changing consumer attitudes toward sustainable transportation. With more than half of the funding already used, the focus will need to shift to sustaining the program and ensuring that it meets the needs of all residents, while complementary incentives like home and workplace charging rebates can amplify its impact.

Ultimately, Washington’s commitment to electric vehicles is not just about rebates; it’s about fostering a comprehensive ecosystem that supports clean energy, infrastructure, and equitable access. By addressing these challenges head-on, the state can continue to lead the way in the transition to electric mobility, benefiting both the environment and its residents in the long run.

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Ontario Hydro Crisis highlights soaring electricity rates, costly subsidies, nuclear refurbishments, and stalled renewables in Ontario. Policy missteps, weak planning, and rising natural gas emissions burden ratepayers while energy efficiency and storage remain underused.

Key Points

High power costs and subsidies from policy errors, nuclear refurbishments, stalled efficiency and renewables in Ontario.

✅ $5.6B yearly subsidy masks electricity rates and deficits

✅ Nuclear refurbishments embed rising costs for decades

✅ Efficiency, storage, and DERs stalled amid weak planning

By Mark Winfield

While the troubled Site C and Muskrat Falls hydroelectric dam projects in B.C. and Newfoundland and Labrador have drawn a great deal of national attention over the past few months, Ontario has quietly been having a hydro crisis of its own.

One of the central promises in the 2018 platform of the Ontario Progressive Conservative party was to “clean up the hydro mess,” and then-PC leader Doug Ford vowed to fire Hydro One's leadership as part of that effort. There certainly is a mess, with the costs of subsidies taken from general provincial revenues to artificially lower hydro rates nearing $7 billion annually. That is a level approaching the province’s total pre-COVID-19 annual deficit. After only two years, that will also exceed total expected cost overruns of the Site C and Muskrat Falls projects, currently estimated at $12 billion ($6 billion each).

There is no doubt that Doug Ford’s government inherited a significant mess around the province’s electricity system from the previous Liberal governments of former premiers Dalton McGuinty and Kathleen Wynne. But the Ford government has also demonstrated a remarkable capacity for undoing the things its predecessors had managed to get right while doubling down on their mistakes.

The Liberals did have some significant achievements. Most notably: coal-fired electricity generation, which constituted 25 per cent of the province’s electricity supply in the early 2000s, was phased out in 2014. The phaseout dramatically improved air quality in the province. There was also a significant growth in renewable energy production. From  virtually zero in 2003, the province installed 4,500 MW of wind-powered generation, and 450 MW of solar photovoltaic by 2018, a total capacity more than double that of the Sir Adam Beck Generating Stations at Niagara Falls.

At the same time, public concerns over rising hydro rates flowing from a major reconstruction of the province’s electricity system from 2003 onwards became a central political issue in the province. But rather than reconsider the role of the key drivers of the continuing rate increases – namely the massively expensive and risky refurbishments of the Darlington and Bruce nuclear facilities, the Liberals adopted a financially ruinous Fair Hydro Plan. The central feature of the 2017 plan was a short-term 25 per cent reduction in hydro rates, financed by removing the provincial portion of the HST from hydro bills, and by extending the amortization period for capital projects within the system. The total cost of the plan in terms of lost revenues and financing costs has been estimated in excess of $40 billion over 29 years, with the burden largely falling on future ratepayers and taxpayers.

Decision-making around the electricity system became deeply politicized, and a secret cabinet forecast of soaring prices intensified public debate across Ontario. Legislation adopted by the Wynne government in 2016 eliminated the requirement for the development of system plans to be subject to any form of meaningful regulatory oversight or review. Instead, the system was guided through directives from the provincial cabinet. Major investments like the Darlington and Bruce refurbishments proceeded without meaningful, public, external reviews of their feasibility, costs or alternatives.

The Ford government proceeded to add more layers to these troubles. The province’s relatively comprehensive framework for energy efficiency was effectively dismantled in March, 2019, with little meaningful replacement. That was despite strong evidence that energy efficiency offered the most cost-effective strategy for reducing greenhouse gas emissions and electricity costs.

The Ford government basically retained the Fair Hydro Plan and promised further rate reductions, later tabling legislation to lower electricity rates as well. To its credit, the government did take steps to clarify real costs of the plan. Last year, these were revealed to amount to a de facto $5.6 billion-per-year subsidy coming from general revenues, and rising. That constituted the major portion of the province’s $7.4 billion pre-COVID-19 deficit. The financial hole was deepened further through November’s financial statement, with the addition of a further $1.3 billion subsidy to commercial and industrial consumers. The numbers can only get worse as the costs of the Darlington and Bruce refurbishments become embedded more fully into electricity rates.

The government also quietly dispensed with the last public vestige of an energy planning framework, relieving itself of the requirement to produce a Long-Term Energy Plan every three years. The next plan would normally have been due next month, in February.

Even the gains from the 2014 phaseout of coal-fired electricity are at risk. Major increases are projected in emissions of greenhouse gases, smog-causing nitrogen oxides and particulate matter from natural gas-fired power plants as the plants are run to cover electricity needs during the Bruce and Darlington refurbishments over the next decade. These developments could erode as much as 40 per cent of the improvements in air quality and greenhouse gas emission gained through the coal phaseout.

The province’s activities around renewable energy, energy storage and distributed energy resources are at a standstill, with exception of a few experimental “sandbox” projects, while other jurisdictions face profound electricity-sector change and adapt. Globally, these technologies are seen as the leading edge of energy-system development and decarbonization. Ontario seems to have chosen to make itself an energy innovation wasteland instead.

The overall result is a system with little or no space for innovation that is embedding ever-higher costs while trying to disguise those costs at enormous expense to the provincial treasury and still failing to provide effective relief to low-income electricity consumers.

The decline in electricity demand associated with the COVID-19 pandemic, along with the introduction of a temporary recovery rate for electricity, gives the province an opportunity to step back and consider its next steps with the electricity system. A phaseout of the Fair Hydro Plan electricity-rate reduction and its replacement with a more cost-effective strategy of targeted relief aimed at those most heavily burdened by rising hydro rates, particularly rural and low-income consumers, as reconnection efforts for nonpayment have underscored the hardship faced by many households, would be a good place to start.

Next, the province needs to conduct a comprehensive, public review of electricity options available to it, including additional renewables – the costs of which have fallen dramatically over the past decade – distributed energy resources, hydro imports from Quebec and energy efficiency before proceeding with further nuclear refurbishments.

In the longer term, a transparent, evidence-based process for electricity system planning needs to be established – one that is subject to substantive public and regulatory oversight and review. Finally, the province needs to establish a new organization to be called Energy Efficiency Ontario to revive its efforts around energy efficiency, developing a comprehensive energy-efficiency strategy for the province, covering electricity and natural gas use, and addressing the needs of marginalized communities.

Without these kinds of steps, the province seems destined to continue to lurch from contradictory decision after contradictory decision as the economic and environmental costs of the system’s existing trajectory continue to rise.

Mark Winfield is a professor of environmental studies at York University and co-chair of the university’s Sustainable Energy Initiative.

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NECEC Clean Energy Connect advances with Maine DEP permits, Hydro-Québec contracts, and rigorous transmission line mitigation, including tapered vegetation, culvert upgrades, and forest conservation, delivering low-carbon power, broadband fiber, and projected ratepayer savings.

Key Points

A Maine transmission project delivering Hydro-Québec power with strict DEP mitigation, lower bills, and added broadband.

✅ DEP permits mandate tapered vegetation, culvert upgrades, land conservation

✅ Hydro-Québec to supply 9.55 TWh/yr via MA contracts; bill savings 2-4%

✅ Added broadband fiber in Somerset and Franklin; local tax benefits

The Maine DEP reviewed the Clean Energy Connect project for more than two years, while regional interest in cross-border transmission continued to grow, before issuing permits that included additional environmental mitigation elements.

"Collectively, the requirements of the permit require an unprecedented level of environmental protection and compensatory land conservation for the construction of a transmission line in the state of Maine," DEP said in a May 11 statement.

Requirements include limits on transmission corridor width, forest preservation, culvert replacement and vegetation management projects, while broader grid programs like vehicle-to-grid integration enhance clean energy utilization across the region.

"In our original proposal we worked hard to develop a project that provided robust mitigation measures to protect the environment," NECEC Transmission CEO Thorn Dickinson said in a statement. "And through this permitting process, we now have made an exceedingly good project even better for Maine."

NECEC will be built on land owned or controlled by Central Maine Power. The 53 miles of new corridor on working forest land will use a new clearing technique for tapered vegetation, while the remainder of the project follows existing power lines.

Environmentalists said they agreed with the decision, and the mitigation measures state regulators took, noting similar momentum behind new wind investments in other parts of Canada.

"Building new ways to deliver low-carbon energy to our region is a critical piece of tackling the climate crisis," CLF Senior Attorney Phelps Turner said in a statement. "DEP was absolutely right to impose significant environmental conditions on this project and ensure that it does not harm critical wildlife areas."

Once complete, Turner said the transmission line will allow the region "to retire dirty fossil fuel plants in the coming years, which is a win for our health and our climate."

The Massachusetts Department of Public Utilities in June 2019 advanced the project by approving contracts for the state's utilities to purchase 9,554,940 MWh annually from Hydro-Quebec. Officials said the project is expected to provide approximately 2% to 4% savings on monthly energy bills.

Total net benefits to Massachusetts ratepayers over the 20-year contract, including both direct and indirect benefits, are expected to be approximately $4 billion, according to the state's estimates.

NECEC "will also deliver significant economic benefits to Maine and the region, including lower electricity prices, increased local real estate taxes and reduced energy costs with examples like battery-backed community microgrids demonstrating local resilience, expanded fiber optic cable for broadband service in Somerset and Franklin counties and funding of economic development for Western Maine," project developers said in a statement.​

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Manitoba Hydro Court Ruling affirms the Public Utilities Board exceeded its jurisdiction by ordering a First Nations rate class, overturning an electricity rates appeal tied to geography, poverty, and regulatory authority in Manitoba.

Key Points

A decision holding the PUB lacked authority to create a First Nations rate class, restoring uniform electricity pricing.

✅ Court says PUB exceeded jurisdiction creating on-reserve rate

✅ Equalized electricity pricing reaffirmed across Manitoba

✅ Geography, not poverty, found decisive in unlawful rate class

Manitoba Hydro was wrongly forced to create a new rate class for electricity customers living on First Nations, the Manitoba Court of Appeal has ruled. 

The court decided the Public Utilities Board "exceeded its jurisdiction" by mandating Indigenous customers on First Nations could have a different electricity rate from other Manitobans. 

The board made the order in 2018, which exempted those customers from the general rate increase that year of 3.6 per cent.

"The directive constituted the creation and implementation of general social policy, an area outside of the PUB's jurisdiction and encroaching into areas that are better suited to the federal and provincial government," says the decision, which was released Tuesday.

Hydro's appeal of the PUB's decision went to court earlier this year.

At the time, the Crown corporation acknowledged many Indigenous people on First Nations live in poverty, but it argued the Public Utilities Board was overstepping its authority in trying to address the issue by creating a new rate class.

It also argued it was against provincial law to charge different rates in different areas of the province.

The PUB, however, insisted that legislation gives it the right to decide which factors are relevant when considering electricity prices, such as social issues. 

Special Manitoba Hydro rate class needed to offset challenges of living on First Nations, appeal court hears
Manitoba Hydro can appeal order to create special First Nation rate
The board had heard evidence that some customers were making "unacceptable" sacrifices to keep the lights on each month.

Decision 'heavy-handed': AMC
The Assembly of Manitoba Chiefs, an intervener in the appeal, had backed the utility board's position. It said on-reserve customers are disproportionately vulnerable to rate hikes over time.

Grand Chief Arlen Dumas said Wednesday he was surprised by the court's ruling. 

He argued Indigenous people are unduly excluded in the setting of electricity rates in Manitoba.

"I will be speaking with my federal and provincial counterparts on how we deal with this issue, because I think it's the wrong [decision]. It's heavy-handed and we need to address it."

The appeal court judges said there is past precedent for setting equal electricity rates, regardless of where customers live. Legislation to that effect was made in the early 2000s and a few years ago, the PUB recognized that geographical limitations should not be imposed on a class of customers.

Since the board's new order didn't extend the same savings to First Nations members who don't live on reserve but face similar financial circumstances, it is clear the deciding factor was geography, rather than poverty or treaty status, the judges said.

Manitoba Hydro temporarily cutting 200 jobs, many of them front-line workers
"In my view, the PUB erred in law when it created an on-reserve class based solely on a geographic region of the province in which customers are located," the decision read.

While Manitoba Hydro objected to the PUB's order in 2018, it still devoted money to create the new customer class.

Spokesperson Bruce Owen said the utility is still studying the impact of the court's decision, but it appreciates the ruling.  

"We all recognize that many people on First Nations have challenges, but our argument was solely on whether or not the PUB had the authority to create a special rate class based on where people live."

Owen added that Hydro recognizes electricity rates can be a hardship on individuals facing poverty. He said those considerations are part of the discussions the corporation has with the utilities board.

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UAE Barakah Nuclear Plant connects Unit 1 to the grid, supplying clean electricity, nuclear baseload power, and lower carbon emissions, with IAEA oversight, FANR regulation, and South Korea collaboration, supporting energy security and economic diversification.

Key Points

The UAE Barakah Nuclear Plant is a four-reactor project delivering clean baseload power and reducing CO2.

✅ Unit 1 online; four reactors to supply 25% of UAE electricity

✅ Cuts 21 million tons CO2 annually; clean baseload for grid

✅ FANR-licensed; IAEA and WANO oversight ensure safety

Unit 1 of the UAE’s Barakah plant — the Arab world’s first nuclear energy plant in the region — has connected to the national power grid, in a historic moment enabling it to provide cleaner electricity to millions of residents and help reduce the oil-rich country’s reliance on fossil fuels. 

“This is a major milestone, we’ve been planning for this for the last 12 years now,” Mohamed Al Hammadi, CEO of Emirates Nuclear Energy Corporation (ENEC), told CNBC’s Dan Murphy in an exclusive interview ahead of the news.

Unit 1, which has reached 100% power as it steps closer to commercial operations, is the first of what will eventually be four reactors, which when fully operational are expected to provide 25% of the UAE’s electricity and reduce its carbon emissions by 21 million tons a year, according to ENEC. That’s roughly equivalent to the carbon emissions of 3.2 million cars annually.

The Gulf country of nearly 10 million is the newest member of a group of now 31 countries running nuclear power operations. It’s also the first new country to launch a nuclear power plant in three decades, the last being China’s nuclear energy program in 1990.

“The UAE has been growing from an electricity demand standpoint,”  Al Hammadi said. “That’s why we are trying to meet the demand (and) at the same time have it with less carbon emissions.”

The UAE’s electricity mix will continue to include gas and renewable energy, with “the baseload from nuclear,” including emerging next-gen nuclear designs, the CEO added, which he described as a “safe, clean and reliable source of electricity” for the country.

The project is also providing “highly compensated jobs” for the Emiratis and will introduce new industries for the country’s economy, Al Hammadi said. The company noted that it has awarded roughly 2,000 contracts worth more than $4.8 billion for local companies.

International collaboration
The UAE’s nuclear watchdog FANR, the Federal Authority for Nuclear Regulation, granted the operating license for Unit 1 in February, after an extensive inspection process to ensure the plant’s compliance with regulatory requirements. The license is expected to last 60 years. The program also involved collaboration with external bodies including the U.N.’s International Atomic Energy Agency (IAEA) and the government of South Korea, and its pre-start-up review was completed in January by the World Association of Nuclear Operators (WANO). The WANO and the IAEA have conducted over 40 inspection and review missions at Barakah.   

But the project has its critics, particularly some experts from the independent Nuclear Consulting Group non-profit, who have expressed concern about Barakah’s safety features and potential environmental risks.  

In response, ENEC said the “adherence to the highest standards of safety, quality and security is deeply embedded within the fabric of the UAE Peaceful Nuclear Energy Program.”

“The Barakah Plant meets all national and international regulatory requirements and standards for nuclear safety,” a  company statement said. It added that the reactor design had been certified by the Korea Institute of Nuclear Safety, FANR and the US-based Nuclear Regulatory Commission, “demonstrating the robustness of this design for safety and operating reliability.”

Worries of regional proliferation 
The achievement for the UAE is particularly significant given tensions in the wider region over nuclear proliferation. 

Some observers have warned of a regional arms race, though the UAE already partakes in what nuclear energy experts call the “gold standard” of civilian nuclear partnerships: The U.S.-UAE 123 Agreement for Peaceful Civilian Nuclear Energy Cooperation. It allows the UAE to receive nuclear materials, equipment and know-how from the U.S. while precluding it from developing dual-use technology by barring uranium enrichment and fuel reprocessing, the processes required for building a bomb.

By contrast, nearby Iran has suspended its compliance to the multilateral 2015 deal that regulated its nuclear power development and many fear its approach toward bomb-making capability. Meanwhile, Saudi Arabia has voiced its desire to develop a nuclear energy program without adhering to a 123 agreement.

And most recently, in the wake of a historic deal that has seen the UAE become the first Gulf country to normalize relations with Israel, Iran responded by warning the agreement would bring a “dangerous future” for the Emirati government. 

But ENEC and UAE officials emphasize the program’s commitment to safety, transparency and international cooperation, and its necessity for meeting growing electricity demand by cleaner means. 

“The nuclear industry is growing, with milestones around the world being reached, and the UAE is no exception. We are pursuing our electricity demand to meet that in a safe, secure and stable manner, and also doing it in an environmentally friendly way,” Al Hammadi said.

“Having four reactors that will provide 25% of electricity for the nation and will avoid us emitting 21 million tons of CO2 on an annual basis, as part of a broader green industrial revolution approach, is a very serious step to take — and the UAE is not talking about it, it is doing it, and we are reaping the benefits of it as we speak right now.”

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