Solar-powered cooker wins $75,000 climate prize

Hydroelectric retrofits for unpowered dams leverage turbines to add renewable capacity, bolster grid reliability, and enable low-impact energy storage, supporting U.S. and Canada decarbonization goals with lower costs, minimal habitat disruption, and climate resilience.

Key Points

They add turbines to existing dams to make clean power, stabilize the grid, and offer low-impact storage at lower cost.

✅ Lower capex than new dams; minimal habitat disruption

✅ Adds firming and storage to support wind and solar

✅ New low-head turbines unlock more retrofit sites

As countries race to get their power grids off fossil fuels to fight climate change, there's a big push in the U.S. to upgrade dams built for purposes such as water management or navigation with a feature they never had before — hydroelectric turbines. 

And the strategy is being used in parts of Canada, too, with growing interest in hydropower from Canada supplying New York and New England.

The U.S. Energy Information Administration says only three per cent of 90,000 U.S. dams currently generate electricity. A 2012 report from the U.S. Department of Energy found that those dams have 12,000 megawatts (MW) of potential hydroelectric generation capacity. (According to the National Hydropower Association, 1 MW can power 750 to 1,000 homes. That means 12,000 MW should be able to power more than nine million homes.)

As of May 2019, there were projects planned to convert 32 unpowered dams to add 330 MW to the grid over the next several years.

One that was recently completed was the Red Rock Hydroelectric Project, a 60-year-old flood control dam on the Des Moines River in Iowa that was retrofitted in 2014 to generate 36.4 MW at normal reservoir levels, and up to 55 MW at high reservoir levels and flows. It started feeding power to the grid this spring, and is expected to generate enough annually to supply power to 18,000 homes.

It's an approach that advocates say can convert more of the grid from fossil fuels to clean energy, often with a lower cost and environmental impact than building new dams.

Hydroelectric facilities can also be used for energy storage, complementing intermittent clean energy sources such as wind and solar with pumped storage to help maintain a more reliable, resilient grid.

The Nature Conservancy and the World Wildlife Fund are two environmental groups that oppose new hydro dams because they can block fish migration, harm water quality, damage surrounding ecosystems and release methane and CO2, and in some regions, Western Canada drought has reduced hydropower output as reservoirs run low. But they say adding turbines to non-powered dams can be part of a shift toward low-impact hydro projects that can support expansion of solar and wind power.

Paul Norris, president of the Ontario Waterpower Association, said there's typically widespread community support for such projects in his province amid ongoing debate over whether Ontario is embracing clean power in its future plans. "Any time that you can better use existing assets, I think that's a good thing."

New turbine technology means water doesn't need to fall from as great a height to generate power, providing opportunities at sites that weren't commercially viable in the past, Norris said, with recent investments such as new turbines in Manitoba showing what is possible.

In Ontario, about 1,000 unpowered dams are owned by various levels of government. "With the appropriate policy framework, many of these assets have the potential to be retrofitted for small hydro," Norris wrote in a letter to Ontario's Independent Electricity System Operator this year as part of a discussion on small-scale local energy generation resources.

He told CBC that several such projects are already in operation, such as a 950 kW retrofit of the McLeod Dam at the Moira River in Belleville, Ont., in 2008. 

Four hydro stations were going to be added during dam refurbishment on the Trent-Severn Waterway, but they were among 758 renewable energy projects cancelled by Premier Doug Ford's government after his election in 2018, a move examined in an analysis of Ontario's dirtier electricity outlook and its implications.

Patrick Bateman, senior vice-president of Waterpower Canada, said such dam retrofit projects are uncommon in most provinces. "I don't see it being a large part of the future electricity generation capacity."

He said there has been less movement on retrofitting unpowered dams in Canada compared to the U.S., because:

There are a lot more opportunities in Canada to refurbish large, existing hydro-generating stations to boost capacity on a bigger scale.

There's less growth in demand for clean energy, because more of Canada's grid is already non-carbon-emitting (80 per cent) compared to the U.S. (40 per cent).

Even so, Norris thinks Canadians should be looking at all opportunities and options when it comes to transitioning the grid away from fossil fuels, including retrofitting non-powered dams, especially as a recent report highlights Canada's looming power problem over the coming decades.

"If we're going to be serious about addressing the inevitable challenges associated with climate change targets and net zero, it really is an all-of-the-above approach."

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EECBG Program Funding empowers states, Tribes, and local governments with DOE grants to deploy clean energy, energy efficiency, EV infrastructure, and community solar, cutting emissions, lowering utility bills, and advancing net-zero decarbonization.

Key Points

EECBG Program Funding is a $550M DOE grant for states, Tribes, and governments to deploy clean energy and efficiency.

✅ Supports EV infrastructure and community solar deployment

✅ Cuts emissions and lowers utility costs via efficiency

✅ Prioritizes Justice40 benefits for underserved communities

The Biden-Harris Administration, through the U.S. Department of Energy (DOE), today released a Notice of Intent announcing $550 million to support community-based clean energy in state, Tribal, and local governments — serving more than 250 million Americans. This investment in American communities, through the Energy Efficiency and Conservation Block Grant (EECBG) Program, will support communities across the country to develop local programming and deploy clean energy technologies to cut emissions, advance a 90% carbon-free electricity goal nationwide, and reduce consumers’ energy costs, and help meet President Biden’s goal of a net-zero economy by 2050. 

“This funding is a streamlined and flexible tool for local governments to build their electricity future with clean energy,” said U.S. Secretary of Energy Jennifer M. Granholm. “State, local, and Tribal communities nationwide will be able to leverage this funding to drive greater energy efficiency and conservation practices to lower utility bills and create healthier environments for American families.”   

The EECBG Program will fund 50 states, five U.S. territories, the District of Columbia, 774 Tribes, and 1,878 local governments in a variety of capacity-building, planning, and infrastructure efforts to reduce carbon emissions and energy use and improve energy efficiency in the transportation, building, and other related sectors. For example, communities with this funding can build out electric vehicle infrastructure and deploy community solar to serve areas that otherwise do not have access to electric vehicles or clean energy, particularly through a rural energy security program where appropriate.  

The $550 million made available through the Bipartisan Infrastructure Law (BIL) represents the second time that the EECBG Program has been funded, the first of which was through the American Recovery and Reinvestment Act of 2009. With this most recent funding, communities can build on prior investments and leverage additional clean energy funding from DOE, other federal agencies, and the private sector to achieve sustained impacts, supported by a Clean Electricity Standard where applicable, that can put their communities on a pathway to decarbonization. 

Through the EECBG Program and the Office of State and Community Energy Programs (SCEP), DOE will support the many diverse state, local, and tribal communities across the U.S., including efforts to revitalize coal communities through clean energy, as they implement this funding and other clean energy projects. To ensure no communities are left behind, the program aligns with President’s Justice40 initiative and efforts toward equity in electricity regulation to help ensure that 40% of the overall benefits of clean energy investments go to underserved and overburdened communities. 

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Pacific Northwest Transmission Bottleneck slows clean energy progress as BPA's aging grid constrains renewable interconnections, delaying wind, solar, and data center growth; decarbonization targets depend on transmission upgrades, new substations, and policy reform.

Key Points

An interconnection and capacity shortfall on BPA's aging grid that delays renewables and impedes clean energy goals.

✅ BPA approvals lag: 1 of 469 projects since 2015.

✅ Yakama solar waits for substation upgrades until 2027.

✅ Data centers and decarbonization targets face grid constraints.

Oregon and Washington have set ambitious targets to decarbonize their power sectors, aiming for 100% clean electricity in the coming decades. However, a significant obstacle stands in the way: the region's aging and overburdened transmission grid, underscoring why 100% renewables remain elusive even as momentum builds.

The Grid Bottleneck

The BPA operates a transmission system that is nearly a century old in some areas, and its capacity has not expanded sufficiently to accommodate the influx of renewable energy projects, reflecting stalled grid spending in many parts of the U.S., according to recent analyses. Since 2015, 469 large renewable projects have applied to connect to the BPA's grid; however, only one has been approved—a stark contrast to other regions in the country. This bottleneck has left numerous wind and solar projects in limbo, unable to deliver power to the grid.

One notable example is the Yakama Nation's solar project. Despite receiving a $32 million federal grant under the bipartisan infrastructure law as part of a broader grid overhaul for renewables, the tribe faces significant delays. The BPA estimates that it will take until 2027 to complete the necessary upgrades to the transmission system, including a new substation, before the solar array can be connected. This timeline poses a risk of losing federal funding if the project isn't operational by 2031.

Economic and Environmental Implications

The slow pace of grid expansion has broader implications for the region's economy and environmental goals. Data centers and other energy-intensive industries are increasingly drawn to the Pacific Northwest due to its clean energy potential, while interregional projects like the Wyoming-to-California wind link illustrate how transmission access can unlock supply. However, without adequate infrastructure, these industries may seek alternatives elsewhere. Additionally, the inability to integrate renewable energy efficiently hampers efforts to reduce greenhouse gas emissions and combat climate change.

Policy Challenges and Legislative Efforts

Efforts to address the grid limitations through state-level initiatives have faced challenges, even as a federal rule to boost transmission advances nationally. In 2025, both Oregon and Washington considered legislation to establish state bonding authorities aimed at financing transmission upgrades. However, these bills failed to pass, leaving the BPA as the primary entity responsible for grid expansion. The BPA's unique structure—operating as a self-funded federal agency without direct state oversight—has made it difficult for regional leaders to influence its decision-making processes.

Looking Ahead

The Pacific Northwest's renewable energy aspirations hinge on modernizing its transmission infrastructure, aligning with decarbonization strategies that emphasize grid buildout. While the BPA has proposed several projects to enhance grid capacity, the timeline for completion remains uncertain. Without significant investment and policy reforms, the region risks falling behind in the transition to a clean energy future. Stakeholders across Oregon and Washington must collaborate to advocate for necessary changes and ensure that the grid can support the growing demand for renewable energy.

The Pacific Northwest's commitment to clean energy is commendable, but achieving these goals requires overcoming substantial infrastructure challenges, and neighboring jurisdictions such as British Columbia have pursued B.C. regulatory streamlining to accelerate projects. Addressing the limitations of the BPA's transmission system is critical to unlocking the full potential of renewable energy in the region. Only through concerted efforts at the federal, state, and local levels can Oregon and Washington hope to realize their green energy ambitions.

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Texas wholesale electricity price spike disrupts ERCOT markets as Griddy and other retail energy providers face surge pricing; customers confront spot market exposure, fixed-rate plan switching, demand response appeals, and deep-freeze grid constraints across Texas.

Key Points

An extreme ERCOT market surge sending real-time rates to caps, exposing Griddy users and driving provider-switch pleas.

✅ Wholesale index plans pass through $9,000/MWh scarcity pricing.

✅ Retailers urge switching; some halt enrollments amid volatility.

✅ Demand response incentives and conservation pleas reduce load.

Some retail power companies in Texas are making an unusual plea to their customers amid a winter storm that has sent electricity prices skyrocketing: Please, leave us.

Power supplier, Griddy, told all 29,000 of its customers that they should switch to another provider as spot electricity prices soared to as high as $9,000 a megawatt-hour. Griddy’s customers are fully exposed to the real-time swings in wholesale power markets, so those who don’t leave soon will face extraordinarily high electricity bills.

“We made the unprecedented decision to tell our customers — whom we worked really hard to get — that they are better off in the near term with another provider,” said Michael Fallquist, chief executive officer of Griddy. “We want what’s right by our consumers, so we are encouraging them to leave. We believe that transparency and that honesty will bring them back” once prices return to normal.

Texas is home to the most competitive electricity market in America. Homeowners and businesses shopping for electricity churn power providers there like credit cards. In the face of such cutthroat competition, retail power providers in the region have grown accustomed to offering new customers incredibly low rates, incentives and, at least in Griddy’s case, unusual plans that allow customers to pay wholesale power prices as opposed to fixed ones.

The ruthless nature of the business has power traders speculating over which firms might have been caught short this week in the most dramatic run-up in spot power prices they’ve ever seen, and even talk of a market bailout has surfaced.

Not all companies are asking customers to leave. Others are just pleading for them to cut back to reduce blackout risks during extreme weather.

Pulse Power, based in The Woodlands, Texas, is offering customers a chance to win a Tesla Model 3, or free electricity for up to a year if they reduce their power usage by 10% in the coming days. Austin-based Bulb is offering $2 per kilowatts-hour, up to $200, for any energy customers save.

Griddy, however, is in a different position. Its service is simple — and controversial. Members pay a $9.99 monthly fee and then pay the cost of spot power traded on Texas’s power grid based on the time of day they use it. Earlier this month, that meant customers were saving money — and at times even getting paid — to use electricity at night. But in recent days, the cost of their power has soared from about 5 to 6 cents a kilowatt-hour to $1 or more. That’s when Fallquist knew it was time to urge his customers to leave.

“I can tell you it was probably one of the hardest decisions we’ve ever made,” he said. “Nobody ever wants to see customers go.”

Griddy isn’t the only one out there actively encouraging its customers to leave. People were posting similar pleas on Twitter over the holiday weekend from other Texas utilities and retail power providers offering everything from $100 rebates to waived cancellation fees as incentives to switch.

Customers may not even be able to switch. Rizwan Nabi, president of energy consultancy Riz Energy in Houston, said several power providers in Texas have told him they aren’t accepting new customers due to this week’s volatile prices, while grid improvements are debated statewide.

Hector Torres, an energy trader in Texas, who is a Griddy customer himself, said he tried to switch services over the long weekend but couldn’t find a company willing to take him until Wednesday, when the weather is forecast to turn warmer.

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Commercial Electric Tariffs explain utility rate structures, peak demand charges, kWh vs kW pricing, time-of-use periods, voltage, delivery, capacity ratchets, and riders, guiding facility managers in tariff analysis for accurate energy savings.

Key Points

Commercial electric tariffs define utility pricing for energy, demand, delivery, time-of-use periods, riders, and ratchet charges.

✅ Separate kWh charges from kW peak demand fees.

✅ Verify time-of-use windows and demand interval length.

✅ Review riders, capacity ratchets, and minimum demand clauses.

Especially during these tough economic times, as major changes to electric bills are debated in some states, facility executives who don’t understand how their power is priced have been disappointed when their energy projects failed to produce expected dollar savings. Here’s how not to be one of them.

Your electric rate is spelled out in a document called a “tariff” that can be downloaded from your utility’s web page. A tariff should clearly spell out the costs for each component that is part of your rate, reflecting cost allocation practices in your region. Don’t be surprised to learn that it contains a bunch of them. Unlike residential electric rates, commercial electric bills are not based solely on the quantity of kilowatt-hours (kWh) consumed in a billing period (in the United States, that’s a month). Instead, different rates may apply to how your power is supplied, how it is delivered via electricity delivery charges, when it was consumed, its voltage, how fast it was used (in kW), and other factors.

If a tariff’s lingo and word structure are too opaque, spend some time with a utility account rep to translate it. Many state utility commissions also have customer advocates that may assist as they explore new utility rate designs that affect customers. Alternatively, for a fee, facility managers can privately chat with an energy consultant.

Common mistakes

Many facility managers try to estimate savings based on an averaged electric rate, i.e., annual electric spend divided by annual kWh. However, in markets where electricity demand is flat, such a number may obscure the fastest rising cost component: monthly peak demand charges, measured in dollars per kW (or kilo-volt-amperes, kVA).

This charge is like a monthly speeding ticket, based solely on the highest speed you drove during that time. In some areas, peak demand charges now account for 30 to 60 percent of a facility’s annual electric spend. When projecting energy cost savings, failing to separately account for kW peak demand and kWh consumption may result in erroneous results, and a lot of questions from the C-suite.

How peak demand charges are calculated varies among utilities. Some base it on the highest average speed of use across one hour in a month, while others may use the highest average speed during a 15- or 30-minute period. Others may average several of the highest speeds within a defined time period (for example, 8 a.m. to 6 p.m. on weekdays). It is whatever your tariff says it is.

Because some power-consuming (or producing) devices, including those tied to smart home electricity networks, vary in their operation or abilities, they may save money on a few — but not all — of those rate components. If an equipment vendor calculates savings from its product by using an average electric rate, take pause. Tell the vendor to return after the proposal has been redone using tariff-based numbers.

When a vendor is the only person calculating potential savings from using a product, there’s also a built-in conflict of interest: The person profiting from an equipment sale should not also be the one calculating its expected financial return. Before signing any energy project contracts, it’s essential that someone independent of the deal reviews projected savings. That person (typically an energy or engineering consultant) should be quite familiar with your facility’s electric tariff, including any special provisions, riders, discounts, etc., that may pertain. When this doesn’t happen, savings often don’t occur as planned. 

For example, some utilities add another form of demand charge, based on the highest kW in a year. It has various names: capacity, contract demand, or the generic term “ratchet charge.” Some utilities also have a minimum ratchet charge which may be based on a percent of a facility’s annual kW peak. It ensures collection of sufficient utility revenue to cover the cost of installed transmission and distribution even when a customer significantly cuts its peak demand.

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Nuclear decarbonization leverages low-carbon electricity, process heat, and hydrogen from advanced reactors and SMRs to electrify industry, buildings, and transport, supporting net-zero strategies and grid flexibility alongside renewables with dispatchable baseload capacity.

Key Points

Nuclear decarbonization uses reactors to supply low-carbon power, heat, and hydrogen, cutting emissions across industry.

✅ Advanced reactors and SMRs enable high-temperature process heat

✅ Nuclear-powered electrolysis and HTSE produce low-carbon hydrogen

✅ District heating from reactors reduces pollution and coal use

By Dr Henri Paillere, Head of the Planning and Economics Studies Section of the IAEA

Decarbonising the power sector will not be sufficient to achieving net-zero emissions, with assessments indicating nuclear may be essential across sectors. We also need to decarbonise the non-power sectors - transport, buildings and industry - which represent 60% of emissions from the energy sector today. The way to do that is: electrification with low-carbon electricity as much as possible; using low-carbon heat sources; and using low-carbon fuels, including hydrogen, produced from clean electricity.
The International Energy Agency (IEA) says that: 'Almost half of the emissions reductions needed to reach net zero by 2050 will need to come from technologies that have not reached the market today.' So there is a need to innovate and push the research, development and deployment of technologies. That includes nuclear beyond electricity.

Today, most of the scenario projections see nuclear's role ONLY in the power sector, despite ongoing debates over whether nuclear power is in decline globally, but increased electrification will require more low-carbon electricity, so potentially more nuclear. Nuclear energy is also a source of low-carbon heat, and could also be used to produce low-carbon fuels such as hydrogen. This is a virtually untapped potential.

There is an opportunity for the nuclear energy sector - from advanced reactors, next-gen nuclear small modular reactors, and non-power applications - but it requires a level playing field, not only in terms of financing today's technologies, but also in terms of promoting innovation and supporting research up to market deployment. And of course technology readiness and economics will be key to their success.

On process heat and district heating, I would draw attention to the fact there have been decades of experience in nuclear district heating. Not well spread, but experience nonetheless, in Russia, Hungary and Switzerland. Last year, we had two new projects. One floating nuclear power plant in Russia (Akademik Lomonosov), which provides not only electricity but district heating to the region of Pevek where it is connected. And in China, the Haiyang nuclear power plant (AP1000 technology) has started delivering commercial district heating. In China, there is an additional motivation to reducing emissions, namely to cut air pollution because in northern China a lot of the heating in winter is provided by coal-fired boilers. By going nuclear with district heating they are therefore cutting down on this pollution and helping with reducing carbon emissions as well. And Poland is looking at high-temperature reactors to replace its fleet of coal-fired boilers and so that's a technology that could also be a game-changer on the industry side.

There have also been decades of research into the production of hydrogen using nuclear energy, but no real deployment. Now, from a climate point of view, there is a clear drive to find substitute fuels for the hydrocarbon fuels that we use today, and multiple new nuclear stations are seen by industry leaders as necessary to meet net-zero targets. In the near term, we will be able to produce hydrogen with electrolysis using low-carbon electricity, from renewables and nuclear. But the cheapest source of low-carbon power is from the long-term operation of existing nuclear power plants which, combined with their high capacity factors, can give the cheapest low-carbon hydrogen of all.

In the mid to long term, there is research on-going with processes that are more efficient than low-temperature electrolysis, which is high temperature steam electrolysis or thermal splitting of water. These may offer higher efficiencies and effectiveness but they also require advanced reactors that are still under development. Demonstration projects are being considered in several countries and we at the IAEA are developing a publication that looks into the business opportunities for nuclear production of hydrogen from existing reactors. In some countries, there is a need to boost the economics of the existing fleet, especially in the electricity systems where you have low or even negative market prices for electricity. So, we are looking at other products that have higher values to improve the competitiveness of existing nuclear power plants.

The future means not only looking at electricity, but also at industry and transport, and so integrated energy systems. Electricity will be the main workhorse of our global decarbonisation effort, but through heat and hydrogen. How you model this is the object of a lot of research work being done by different institutes and we at the IAEA are developing some modelling capabilities with the objective of optimising low-carbon emissions and overall costs.

This is just a picture of what the future might look like: a low-carbon power system with nuclear lightwater reactors (large reactors, small modular reactors and fast reactors) drawing on the green industrial revolution reactor waves in planning; solar, wind, anything that produces low-carbon electricity that can be used to electrify industry, transport, and the heating and cooling of buildings. But we know there is a need for high-temperature process steam that electricity cannot bring but which can be delivered directly by high-temperature reactors. And there are a number of ways of producing low-carbon hydrogen. The beauty of hydrogen is that it can be stored and it could possibly be injected into gas networks that could be run in the future on 100% hydrogen, and this could be converted back into electricity.

So, for decarbonising power, there are many options - nuclear, hydro, variable renewables, with renewables poised to surpass coal in global generation, and fossil with carbon capture and storage - and it's up to countries and industries to invest in the ones they prefer. We find that nuclear can actually reduce the overall cost of systems due to its dispatchability and the fact that variable renewables have a cost because of their intermittency. There is a need for appropriate market designs and the role of governments to encourage investments in nuclear.

Decarbonising other sectors will be as important as decarbonising electricity, from ways to produce low-carbon heat and low-carbon hydrogen. It's not so obvious who will be the clear winners, but I would say that since nuclear can produce all three low-carbon vectors - electricity, heat and hydrogen - it should have the advantage.
We at the IAEA will be organising a webinar next month with the IEA looking at long-term nuclear projections in a net-zero world, building on IAEA analysis on COVID-19 and low-carbon electricity insights. That will be our contribution from the point of view of nuclear to the IEA's special report on roadmaps to net zero that it will publish in May.

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