Electricity News in July 2023
Why the Texas Power Grid Is Facing Another Crisis
Texas Power Grid Reliability faces record peak demand as ERCOT balances renewable energy, wind and solar variability, gas-fired generation, demand response, and transmission limits to prevent blackouts during heat waves and extreme weather.
Key Points
Texas Power Grid Reliability is ERCOT's capacity to meet peak demand with diverse resources while limiting outages.
✅ Record heat drives peak demand across ERCOT.
✅ Variable wind/solar need firm, flexible capacity.
✅ Demand response and reserves reduce blackout risk.
The electric power grid in Texas, which collapsed dramatically during the 2021 winter storm across the state, is being tested again as the state suffers unusually hot summer weather. Demand for electricity has reached new records at a time of rapid change in the mix of power sources as wind and solar ramp up. That’s feeding a debate about the dependability of the state’s power.
1. Why is the Texas grid under threat again?
Already the biggest power user in the nation, electricity use in the second most-populous state surged to record levels during heat waves this summer. The jump in demand comes as the state becomes more dependent on intermittent renewable power sources, raising concerns among some critics that more reliance on wind and solar will leave the grid more vulnerable to disruption. Green sources will produce almost 40% of the power in Texas this year, US Energy Information Administration data show. While that trails California’s 52%, Texas is a bigger market. It’s already No. 1 in wind, making it the largest clean energy market in the US.
2. How is Texas unique?
The spirit of defiance of the Lone Star State extends to its power grid as well. The Electric Reliability Council of Texas, or Ercot as the grid operator is known, serves about 90% of the state’s electricity needs and has very few high-voltage transmission lines connecting to nearby grids. It’s a deliberate move to avoid federal oversight of the power market. That means Texas has to be mainly self-reliant and cannot depend on neighbors during extreme conditions. That vulnerability is a dramatic twist for a state that’s also the energy capital of the US, thanks to vast oil and natural gas producing fields. Favorable regulations are also driving a wind and solar boom in Texas.
3. Why the worry?
The summer of 2023 will mark the first time all of the state’s needs cannot be met by traditional power plants, like nuclear, coal and gas. A sign of potential trouble came on June 20 when state officials urged residents to conserve power because of low supplies from wind farms and unexpected closures of fossil-fuel generators amid supply-chain constraints that limited availability. As of late July, the grid was holding up, thanks to the help of renewable sources. Solar generation has been coming in close to expected summer capacity, or exceeding it on most days. This has helped offset the hours in the middle of the day when wind speeds died down in West Texas.
4. Why didn’t the grid’s problems get fixed?
There is no easy fix. The Texas system allows the price of electricity to swing to match supply and demand. That means high prices — and high profits — drive the development of new power plants. At times spot power prices have been as low as $20-$50 a megawatt-hour versus more than $4,000 during periods of stress. The limitation of this pricing structure was laid bare by the 2021 winter blackouts. Since then, state lawmakers have passed market reforms that require weatherization of critical infrastructure and changed rules to put more money in the pockets of the owners of power generation.
5. What’s the big challenge?
There’s a real clash going on over what the grid of the future should look like in Texas and across the country, especially as severe heat raises blackout risks nationally. The challenge is to make sure nuclear and fossil fuel plants that are needed right now don’t retire too early and still allow newer, cleaner technologies to flourish. Some conservative Republicans have blamed renewable energy for destabilizing the grid and have pushed for more fossil-fuel powered generators. Lawmakers passed a controversial $10 billion program providing low-interest loans and grants to build new gas-fired plants using taxpayer money, but Texans ultimately have to vote on the subsidy.
6. Why do improvements take so long?
Figuring out how to keep the lights on without overburdening consumers is becoming a greater challenge amid more extreme weather fueled by climate change. As such, changing the rules is often a hotly contested process pitting utilities, generators, manufacturers, electricity retailers and other groups against one another. The process became more politicized after the storm in 2021 with Republican Gov. Greg Abbott and lawmakers ordering Ercot to make changes. Building more transmission lines and connecting to other states can help, but such projects are typically tied up for years in red tape.
7. What can be done?
The price cap for electricity was cut from $9,000/MWh to $5,000 to help avoid the punitive costs seen in the 2021 storm, though prices are allowed to spike more easily. Ercot is also contracting for more reserves to be online to help avoid supply shortfalls and improve reliability for customers, which added $1.7 billion in consumer costs alone last year. Another rule helps some gas generators pay for their fuel costs, while a more recent reform put in price floors when reserves fall to certain levels. Many power experts say that the easiest solution is to pay people to reduce their energy consumption during times of grid stress through so-called demand response programs. Factories, Bitcoin miners and other large users are already compensated to conserve during tight grid conditions.
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Are major changes coming to your electric bill?
California Income-Based Electricity Rates propose a fixed monthly fee set by income as utilities and the CPUC weigh progressive pricing, aiming to cut low-income bills while PG&E, SCE, and SDG&E retain usage-based charges.
Key Points
CPUC plan adds income-tiered fixed fees to lower low-income bills while keeping per-kWh usage charges.
✅ Adds fixed monthly fees by income to complement per-kWh charges
✅ Cuts bills for low-income households; higher earners pay more
✅ Utilities say revenue neutral; conservation signals preserved
California’s electric bills — already some of the highest in the nation — are rising as electricity prices soar across the state, but regulators are debating a new plan to charge customers based on their income level.
Typically what you pay for electricity depends on how much you use. But the state’s three largest electric utilities — Southern California Edison Company, Pacific Gas and Electric Company and San Diego Gas & Electric Company — have proposed a plan to charge customers not just for how much energy they use, but also based on their household income, moving toward income-based flat-fee utility bills over time. Their proposal is one of several state regulators received designed to accommodate a new law to make energy less costly for California’s lowest-income customers.
Some state Republican lawmakers are warning the changes could produce unintended results, such as weakening incentives to conserve electricity or raising costs for customers using solar energy, and some have introduced a plan to overturn the charges in the Legislature.
But the utility companies say the measure would reduce electricity bills for the lowest income customers. Those residents would save about $300 per year, utilities estimate.
California households earning more than $180,000 a year would end up paying an average of $500 more a year on their electricity bills, according to the proposal from utility companies.
The California Public Utilities Commission’s deadline for deciding on the suggested changes is July 1, 2024, as regulators face calls for action from consumers and advocates. The proposals come at a time when many moderate and low-income families are being priced out of California by rising housing costs.
Who wants to change the fee structure?
Lawmakers passed and Gov. Gavin Newsom signed a comprehensive energy bill last summer that mandates restructuring electricity pricing across the state.
The Legislature passed the measure in a “trailer-bill” process that limited deliberation. Included in the 21,000-word law are a few sentences requiring the public utilities commission to establish a “fixed monthly fee” based on each customer’s household income.
A similar idea was first proposed in 2021 by researchers at UC Berkeley and the nonprofit thinktank Next 10. Their main recommendation was to split utility costs into two buckets. Fixed charges, which everyone has to pay just to be connected to the energy grid, would be based on income levels. Variable charges would depend on how much electricity you use.
Utilities say that part of customers’ bills still will be based on usage, but the other portion will reduce costs for lower- and middle-income customers, who “pay a greater percentage of their income towards their electricity bill relative to higher income customers,” the utilities argued in a recent filing.
They said the current billing system is unjust, regressive and fails to recognize differences in energy usage among households,
“When we were putting together the reform proposal, front and center in our mind were customers who live paycheck to paycheck, who struggle to pay for essentials such as energy, housing and food,” Caroline Winn, CEO of San Diego Gas & Electric in a statement.
The utilities say in their proposal that the changes likely would not reduce or increase their revenues.
James Sallee, an associate professor at UC Berkeley, said the utilities’ prior system of billing customers mostly by measuring their electric use to pay for what are essentially fixed costs for power is inefficient and regressive.
The proposed changes “will shift the burden, on average, to a more progressive system that recovers more from higher income households and less from lower income households,” he said.
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Two-thirds of the U.S. is at risk of power outages this summer
Home Energy Independence reduces electricity costs and outage risks with solar panels, EV charging, battery storage, net metering, and smart inverters, helping homeowners offset tiered rates and improve grid resilience and reliability.
Key Points
Home Energy Independence pairs solar, batteries, and smart EV charging to lower bills and keep power on during outages.
✅ Offset rising electricity rates via solar and net metering
✅ Add battery storage for backup power and peak shaving
✅ Optimize EV charging to avoid tiered rate penalties
The Department of Energy recently warned that two-thirds of the U.S. is at risk of losing power this summer. It’s an increasingly common refrain: Homeowners want to be less reliant on the aging power grid and don’t want to be at the mercy of electric utilities due to rising energy costs and dwindling faith in the power grid’s reliability.
And it makes sense. While the inflated price of eggs and butter made headlines earlier this year, electricity prices quietly increased at twice the rate of overall inflation in 2022, even as studies indicate renewables aren’t making power more expensive overall, and homeowners have taken notice. In fact, according to Aurora Solar’s Industry Snapshot, 62% expect energy prices will continue to rise.
Homeowners aren’t just frustrated that electricity is pricey when they need it, they’re also worried it won’t be available at all when they feel the most vulnerable. Nearly half (48%) of homeowners are concerned about power outages stemming from weather events, or grid imbalances from excess solar in some regions, followed closely by outages due to cyberattacks on the power grid.
These concerns around reliability and cost are creating a deep lack of confidence in the power grid. Yet, despite these growing concerns, homeowners are increasingly using electricity to displace other fuel sources.
The electrification of everything
From electric heat pumps to electric stoves and clothes dryers, homeowners are accelerating the electrification of their homes. Perhaps the most exciting example is electric vehicle (EV) adoption and the need for home charging. With major vehicle makers committing to ambitious electric vehicle targets and even going all-electric in the future, EVs are primed to make an even bigger splash in the years to come.
The by-product of this electrification movement is, of course, higher electric bills because of increased consumption. Homeowners also risk paying more for every unit of energy they use if they’re part of a tiered pricing utility structure, where energy-insecure households often pay 27% more on electricity because customers are charged different rates based on the total amount of energy they use. Many new electric vehicle owners don’t realize this until they are deep into purchasing their new vehicle, or even when they open that first electric bill after the car is in their driveway.
Sure, this electrification movement can feel counterintuitive given the power grid concerns. But it’s actually the first step toward energy independence, and emerging models like peer-to-peer energy sharing could amplify that over time.
Balancing conflicting movements
The fact is that electrification is moving forward quickly, even among homeowners who are concerned about electricity prices and power grid reliability, and about why the grid isn’t yet 100% renewable in the U.S. This has the potential to lead to even more discontent with electric utilities and growing anxiety over access to electricity in extreme situations. There is a third trend, though, that can help reconcile these two conflicting movements: the growth of solar.
The popularity of solar is likely higher than you think: Nearly 77% of homeowners either have solar panels on their homes or are interested in purchasing solar. The Aurora Solar Industry Snapshot report also showed a nearly 40% year-over-year increase in residential solar projects across the U.S. in 2022, as the country moves toward 30% power from wind and solar overall, aligning with the Solar Energy Industries Association’s (SEIA) Solar Market Insight Report, which found, “Residential solar had a record year [in 2022] with nearly 6 GWdc of installations, representing 40% growth over 2021.”
It makes sense that finding ways to tamp down—even eliminate—growing bills caused by the electrification of homes is accelerating interest in solar, as more households weigh whether residential solar is worth it for their budgets, and residential solar installers are seeing this firsthand. The link between EVs and solar is a great proof point: Almost 80% of solar professionals said EV adoption often drives new interest in solar.
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US Automakers Will Build 30,000 Electric Vehicle Chargers
Automaker EV Fast-Charging Network will deploy 30,000 DC fast chargers across US and Canada, supporting CCS and NACS, integrating Tesla compatibility, easing range anxiety, and expanding highway and urban charging infrastructure with amenities and uptime.
Key Points
A $1B joint venture by seven automakers to build 30,000 DC fast chargers with CCS and NACS across the US and Canada.
✅ 30,000 DC fast chargers by 2030 across US and Canada
✅ Supports CCS and NACS; Tesla compatibility planned
✅ Launching mid-2024; focus on highways, urban hubs, amenities
Seven major automakers announced a plan on Wednesday to nearly double the number of fast chargers in the United States in an effort to address one of the main reasons that people hesitate to buy electric cars, even as the age of electric cars accelerates.
The carmakers — BMW Group, General Motors, Honda, Hyundai, Kia, Mercedes-Benz Group and Stellantis — will initially invest at least $1 billion in a joint venture that will build 30,000 charging ports on major highways and other locations in the United States and Canada.
The United States and Canada have about 36,000 fast chargers — those that can replenish a drained battery in 30 minutes or less. In some sparsely populated areas, such chargers can be hundreds of miles apart. Surveys show that fear about not being able to find a charger during longer journeys is a major reason that some car buyers are reluctant to buy electric vehicles.
Sales of electric vehicles have risen quickly in the United States as the market hits an inflection point, but there are signs that demand is softening. As a result, Tesla, Ford and other carmakers have cut prices in recent months and are offering incentives. Popular models that had long waiting lists last year are now available in a few days or weeks.
Major carmakers are investing billions of dollars to manufacture electric vehicles and batteries and to establish supplier networks. Having staked their futures on the technology, they have a strong incentive to ensure that electric vehicles catch on with car buyers, even as gas-electric hybrids help bridge the transition.
The chargers installed by the joint venture will have plugs designed for the connections used by most carmakers other than Tesla, as well as the standard developed by Tesla, amid fights for control over charging, that Ford, G.M. and other companies have said they intend to switch to in 2025.
“The better experience people have, the faster E.V. adoption will grow,” Mary T. Barra, the chief executive of General Motors, said in a statement.
The seven automakers plan to formalize the joint venture and announce its name by the end of the year, Chris Martin, a Honda spokesman, said. The first chargers will begin operating around the middle of 2024, he said, with all 30,000 in place by the end of the decade.
The joint venture is open to adding other partners, he said. Among major automakers, Ford was a notable absence from the announcement on Wednesday. The company said in a statement on Wednesday that it would continue to iThe partnership also does not include Volkswagen. The company is a majority shareholder of Electrify America, one of the largest fast-charging providers.
Tesla accounts for more than half the fast chargers in the United States and has said it will open its networks to other car brands, though, so far, it has only made fewer than 100 ports available. Owners of Ford and G.M. vehicles, among others, will be able to connect to 12,000 Tesla fast chargers using an adapter beginning next year. In 2025, Ford and G.M. plan to make models designed to take the Tesla plug without an adapter.
The decision by the seven carmakers to form the joint venture is an indication that they do not intend to rely solely on Tesla, which dominates sales of electric vehicles, for charging.
The chargers being built by the joint venture will be concentrated in urban areas and along major highways, especially those used most heavily by vacationers and other travelers, the companies said in a joint statement. Charging stations will be close to restrooms, restaurants and other amenities. The partners said they would try to take advantage of federal and state funds available for charging infrastructure amid questions about whether the U.S. has the power to charge it at scale.
Most electric vehicle owners charge at home and rarely need to use public chargers. Home chargers typically replenish batteries overnight. Most public chargers, about 125,000 in the United States and Canada, also operate relatively slowly — taking four to 10 hours to do the job.nvest in its own network, which allows Ford owners to charge from a variety of providers with one mobile phone app.
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Energy-hungry Europe to brighten profit at US solar equipment makers
European Solar Inverter Demand surges as photovoltaics and residential solar expand during the clean energy transition, driven by high natural gas prices; Germany leads, boosting Enphase and SolarEdge sales for rooftop systems and grid-tied installations.
Key Points
Rising European need for solar inverters, fueled by residential PV growth, high energy costs, and clean energy policies.
✅ Germany leads EU rooftop PV installations
✅ Enphase and SolarEdge see revenue growth
✅ High gas prices and policies spur adoption
Solar equipment makers are expected to post higher quarterly profit, benefiting from strong demand in Europe for critical components that convert energy from the sun into electricity, amid record renewable momentum worldwide.
The continent is emerging as a major market for solar firms as it looks to reduce its dependence on the Russian energy supply and accelerate its clean energy transition, with solar already reshaping power prices in Northern Europe across the region, brightening up businesses of companies such as Enphase Energy (ENPH.O) and SolarEdge Technologies (SEDG.O), which make solar inverters.
Wall Street expects Enphase and SolarEdge to post a combined adjusted net income of $323.8 million for the April-June quarter, a 56.7% jump from a year earlier, even as demand growth slows in the United States.
The energy crisis in Europe is not as acute as last year when Western sanctions on Russia severely crimped supplies, but prices of natural gas and electricity continue to be much higher than in the United States, Raymond James analyst Pavel Molchanov said.
As a result, demand for residential solar keeps growing at a strong pace in the region, with Germany being one of the top markets and solar adoption in Poland also accelerating in recent years across the region.
About 159,000 residential solar systems became operational in the first quarter in Germany amid a solar power boost that reflects policy and demand, a 146% rise from a year earlier, according to BSW solar power association.
Adoption of solar is also helping European homeowners have greater control over their energy costs as fossil fuel prices tend to be more volatile, Morningstar analyst Brett Castelli said.
SolarEdge, which has a bigger exposure to Europe than Enphase, said its first-quarter revenue from the continent more than doubled compared with last year.
In comparison, growth in the United States has been tepid due to lukewarm demand in states like Texas and Arizona where cheaper electricity prices make the economics of residential solar less attractive, even though solar is now cheaper than gas in parts of the U.S. market.
Higher interest rates following the U.S. Federal Reserve's recent actions to tame inflation are also weighing on demand, even as power outage risks rise across the United States.
Analysts also expect weakness in California where a new metering reform reduces the money credited to rooftop solar owners for sending excess power into the grid, underscoring how policy shifts can reshape the sector. The sunshine state accounts for nearly a third of the U.S. residential solar market.
Enphase will report its results on Thursday after the bell, while SolarEdge will release its second-quarter numbers on Aug. 1.
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France nuclear power stations to limit energy output due to high river temps
France Nuclear Heatwave Restrictions signal reduced nuclear power along the Rhone River as EDF imposes output limits due to high water temperatures, grid needs, with minimal price impact amid strong solar and exports.
Key Points
Temporary EDF output limits at Rhone River reactors due to hot water, protecting ecosystems and grid reliability.
✅ EDF expects halved output at Bugey and Saint Alban.
✅ Cuts align with water temperature and discharge rules.
✅ Weekend midday curtailments offset by solar supply.
The high temperature warning has come early this year but will affect fewer nuclear power plants. High temperatures could halve nuclear power production, with river temperature limits at plants along France's Rhone River this week.
Output restrictions are expected at two nuclear plants in eastern France due to high temperature forecasts, nuclear operator EDF said. It comes several days ahead of a similar warning that was made last year but will affect fewer plants, and follows a period when power demand has held firm during lockdowns across Europe.
The hot weather is likely to halve the available power supply from the 3.6 GW Bugey plant from 13 July and the 2.6 GW Saint Alban plant from 16 July, the operator said.
However, production will be at least 1.8 GW at Bugey and 1.3 GW at Saint Alban to meet grid requirements, and may change according to grid needs, the operator said.
Kpler analyst Emeric de Vigan said the restrictions were likely to have little effect on output in practice. Cuts are likely only at the weekend or midday when solar output was at its peak so the impact on power prices would be slim.
He said the situation would need monitoring in the coming weeks, however, noting it was unusually early in the summer for nuclear-powered France to see such restrictions imposed.
Water temperatures at the Bugey plant already eclipsed the initial threshold for restrictions on 9 July, as European power hits records during the heatwave. They are currently forecast to peak next week and then drop again, Refinitiv data showed.
"France is currently net exporting large amounts of power – and, despite a nuclear power dispute with Germany, single nuclear units' supply restrictions will not have the same effect as last year," Refinitiv analyst Nathalie Gerl said.
The Garonne River in southern France has the highest potential for critical levels of warming, but its Golfech plant is currently offline for maintenance until mid-August, as Europe faces nuclear losses, the data showed.
"(The restrictions were) to be expected and it will probably occur more often," Greenpeace campaigner Roger Spautz said.
"The authorities must stick to existing regulations for water discharges. Otherwise, the ecosystems will be even more affected," he added.
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Mines found at Ukraine's Zaporizhzhia nuclear plant, UN watchdog says
Zaporizhzhia Nuclear Plant Mines reported by IAEA at the Russian-occupied site: anti-personnel devices in a buffer zone, restricted areas; access limits to reactor rooftops and turbine halls heighten nuclear safety and security concerns in Ukraine.
Key Points
IAEA reports anti-personnel mines at Russian-held Zaporizhzhia, raising nuclear safety risks in buffer zones.
✅ IAEA observes mines in buffer zone at occupied site
✅ Restricted areas; no roof or turbine hall access granted
✅ Safety systems unaffected, but staff under pressure
The United Nations atomic watchdog said it saw anti-personnel mines at the site of Ukraine's Zaporizhzhia nuclear power plant which is occupied by Russian forces.
Europe's largest nuclear facility fell to Russian forces shortly after the invasion of Ukraine in February last year, as Moscow later sought to build power lines to reactivate it amid ongoing control of the area. Kyiv and Moscow have since accused each other of planning an incident at the site.
On July 23 International Atomic Energy Agency (IAEA) experts "saw some mines located in a buffer zone between the site's internal and external perimeter barriers," agency chief Rafael Grossi said in a statement on Monday.
The statement did not say how many mines the team had seen.
The devices were in "restricted areas" that operating plant personnel cannot access, Mr Grossi said, adding the IAEA's initial assessment was that any detonation "should not affect the site's nuclear safety and security systems".
Laying explosives at the site was "inconsistent with the IAEA safety standards and nuclear security guidance" and, amid controversial proposals on Ukraine's nuclear plants that have circulated internationally, created additional psychological pressure on staff, he added.
Ukrainians in Nikopol are out of water and within Russia's firing line. But Zaporizhzhia nuclear power plant could pose the biggest threat, even as Ukraine has resumed electricity exports to regional grids.
Last week the IAEA said its experts had carried out inspections at the plant, without "observing" the presence of any mines, although they had not been given access to the rooftops of the reactor buildings, while a possible agreement to curb attacks on plants was being discussed.
The IAEA had still not been given access to the roofs of the reactor buildings and their turbine halls, its latest statement said, even as a proposal to control Ukraine's nuclear plants drew scrutiny.
After falling into Russian hands, Europe's biggest power plant was targeted by gunfire and has been severed from the grid several times, raising nuclear risk warnings from the IAEA and others.
The six reactor units, which before the war produced around a fifth of Ukraine's electricity, have been shut down for months, prompting interest in wind power development as a harder-to-disrupt source.
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Updated Germany hydrogen strategy sees heavy reliance on imported fuel
Germany Hydrogen Import Strategy outlines reliance on green hydrogen imports, expanded electrolysis capacity, IPCEI-funded pipelines, and industrial decarbonization for steel and chemicals to reach climate-neutral goals by 2045, meeting 2030 demand of 95-130 TWh.
Key Points
A plan to import 50-70% of hydrogen by 2030, backing green hydrogen, electrolysis, pipelines, and decarbonization.
✅ Imports cover 50-70% of 2030 hydrogen demand
✅ 10 GW electrolysis target with state aid and IPCEI
✅ 1,800 km H2 pipelines to link hubs by 2030
Germany will have to import up to 70% of its hydrogen demand in the future as Europe's largest economy aims to become climate-neutral by 2045, an updated government strategy published on Wednesday showed.
The German cabinet approved a new hydrogen strategy, setting guidelines for hydrogen production, transport infrastructure and market plans.
Germany is seeking to expand reliance on hydrogen as a future energy source to bolster energy resilience and cut greenhouse emissions for highly polluting industrial sectors that cannot be electrified such as steel and chemicals and cut dependency on imported fossil fuel.
Produced using solar and wind power, green hydrogen is a pillar of Berlin's plan to build a sustainable electric planet and transition away from fossil fuels.
But even with doubling the country's domestic electrolysis capacity target for 2030 to at least 10 gigawatts (GW), Germany will need to import around 50% to 70% of its hydrogen demand, forecast at 95 to 130 TWh in 2030, the strategy showed.
"A domestic supply that fully covers demand does not make economic sense or serve the transformation processes resulting from the energy transition and the broader global energy transition overall," the document said.
The strategy underscores the importance of diversifying future hydrogen sources, including potential partners such as Canada's clean hydrogen sector, but the government is working on a separate strategy for hydrogen imports whose exact date is not clear, a spokesperson for the economy ministry said.
"Instead of relying on domestic potential for the production of green hydrogen, the federal government's strategy is primarily aimed at imports by ship," Simone Peter, the head of Germany's renewable energy association, said.
Under the strategy, state aid is expected to be approved for around 2.5 GW of electrolysis projects in Germany this year and the government will earmark 700 million euros ($775 million) for hydrogen research to optimise production methods, research minister Bettina Stark-Watzinger said.
But Germany's limited renewable energy space will make it heavily dependent on imported hydrogen from emerging export hubs such as Abu Dhabi hydrogen exports gaining scale, experts say.
"Germany is a densely populated country. We simply need space for wind and photovoltaic to be able to produce the hydrogen," Philipp Heilmaier, an energy transition researcher at Germany energy agency, told Reuters.
The strategy allows the usage of hydrogen produced through fossil energy sources preferably if the carbon is split off, but said direct government subsidies would be limited to green hydrogen.
Funds for launching a hydrogen network with more than 1,800 km of pipelines in Germany are expected to flow by 2027/2028 through the bloc's Important Projects of Common European Interest (IPCEI) financing scheme, as the EU plans to double electricity use by 2050 could raise future demand, with the goal of connecting all major generation, import and storage centres to customers by 2030.
Transport Minister Volker Wissing said his ministry was working on plans for a network of hydrogen filling stations and for renewable fuel subsidies.
Environmental groups said the strategy lacked binding sustainability criteria and restriction on using hydrogen for sectors that cannot be electrified instead of using it for private heating or in cars, calling for a plan to eventually phase-out blue hydrogen which is produced from natural gas.
Germany has already signed several hydrogen cooperation agreements with countries such as clean energy partnership with Canada and Norway, United Arab Emirates and Australia.
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Australia's energy transition stalled by stubbornly high demand
Australia Renewable Energy Transition: solar capacity growth, net-zero goals, rising electricity demand, coal reliance, EV adoption, grid decarbonization, heat waves, air conditioning loads, and policy incentives shaping clean power, efficiency, and emissions reduction.
Key Points
Australia targets net-zero by 2050 by scaling renewables, curbing demand, and phasing down coal and gas.
✅ Solar capacity up 200% since 2018, yet coal remains dominant.
✅ Transport leads energy use; EV uptake lags global average.
✅ Heat waves boost AC load, stressing grids and emissions goals.
A more than 200% increase in installed solar power generation capacity since 2018 helped Australia rank sixth globally in terms of solar capacity last year and emerge as one of the world's fastest-growing major renewable energy producers, aligning with forecasts that renewables to surpass coal in global power generation by 2025.
However, to realise its goal of becoming a net-zero carbon emitter by 2050, Australia must reverse the trajectory of its energy use, which remains on a rising path, even as Asia set to use half of electricity underscores regional demand growth, in contrast with several peers that have curbed energy use in recent years.
Australia's total electricity consumption has grown nearly 8% over the past decade, amid a global power demand surge that has exceeded pre-pandemic levels, compared with contractions over the same period of more than 7% in France, Germany and Japan, and a 14% drop in the United Kingdom, data from Ember shows.
Sustained growth in Australia's electricity demand has in turn meant that power producers must continue to heavily rely on coal for electricity generation on top of recent additions in supply of renewable energy sources, with low-emissions generation growth expected to cover most new demand.
Australia has sharply boosted clean energy capacity in recent years, but remains heavily reliant on coal & natural gas for electricity generation
To accomplish emissions reduction targets on time, Australia's energy use must decline while clean energy supplies climb further, as that would give power producers the scope to shut high-polluting fossil-powered energy generation systems ahead of the 2050 deadline.
DEMAND DRIVERS
Reducing overall electricity and energy use is a major challenge in all countries, where China's electricity appetite highlights shifting consumption patterns, but will be especially tough in Australia which is a relative laggard in terms of the electrification of transport systems and is prone to sustained heat waves that trigger heavy use of air conditioners.
The transport sector uses more energy than any other part of the Australian economy, including industry, and accounted for roughly 40% of total final energy use as of 2020, according to the International Energy Agency (IEA.)
Transport energy demand has also expanded more quickly than other sectors, growing by over 5% from 2010 to 2020 compared to industry's 1.3% growth over the same period.
Transport is Australia's main energy use sector, and oil products are the main source of energy type
To reduce energy use, and cut the country's fuel import bill which topped AUD $65 billion in 2022 alone, according to the Australian Bureau of Statistics, the Australian government is keen to electrify car fleets and is offering large incentives for electric vehicle purchases.
Even so, electric vehicles accounted for only 5.1% of total Australian car sales in 2022, according to the International Energy Agency (IEA).
That compares to 13% in New Zealand, 21% in the European Union, and a global average of 14%.
More incentives for EV purchases are expected, but any rapid adoption of EVs would only serve to increase overall electricity demand, and with surging electricity demand already straining power systems worldwide, place further pressure on power producers to increase electricity supplies.
Heating and cooling for homes and businesses is another major energy demand driver in Australia, and accounts for roughly 40% of total electricity use in the country.
Australia is exposed to harsh weather conditions, especially heat waves which are expected to increase in frequency, intensity and duration over the coming decades due to climate change, according to the New South Wales government.
To cope, Australians are expected to resort to increased use of air conditioners during the hottest times of the year, and with reduced power reserves flagged by the market operator, adding yet more strain to electricity systems.
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Tesla Electric is preparing to expand in the UK
Tesla Electric UK Expansion signals retail energy entry, leveraging Powerwall VPPs for grid services, dynamic pricing, and energy trading, building on Texas success and Octopus Energy ties to buy and sell electricity automatically.
Key Points
Tesla's plan to launch Tesla Electric in the UK, using Powerwall VPPs to retail energy, trade power, and hedge peaks.
✅ Retail energy model built on Powerwall VPP aggregation
✅ Automated buy-sell arbitrage with dynamic pricing
✅ Leverages prior UK approval and Octopus Energy ties
According to a new job posting, Tesla Electric, Tesla’s new electric utility division, is preparing to expand in the United Kingdom as regions such as California grid planners look to electric vehicles for stability to manage demand.
Late last year, after gaining experience through its virtual power plants (VPPs), including response during California blackouts that pressured the grid, Tesla took things a step further with the launch of “Tesla Electric.”
Instead of reacting to specific “events” and providing services to your local electric utilities through demand response programs, as Tesla Powerwall owners have done in VPPs in California, Tesla Electric is actively and automatically buying and selling electricity for Tesla Powerwall owners – providing a buffer against peak prices.
The company is essentially becoming an energy retailer, aligning with a major future for its energy business envisioned by leadership.
Tesla Electric is currently only available to Powerwall owners in Texas, but the company has plans to expand its products through this new division.
We recently reported on Tesla Electric customers in Texas making as much as $150 a day selling electricity back to the grid through the program.
Now Tesla is looking to expand Tesla Electric to the UK, where grid capacity for rising EV demand remains a key consideration.
The company has listed a new job posting for a role called “Head of Operations, Tesla Electric – Retail Energy.”
This has been in the works for a while now. Tesla used to have a partnership with Octopus Energy in the UK for special electricity rates for its owners, during a period when UK EV inquiries surged amid a fuel supply crisis, but it seemed to be a stepping stone before it would itself become an energy provider in the market.
In 2020, Tesla was officially approved as an electricity retailer in the UK. Now it looks like Tesla is going to use this approval with the launch of Tesla Electric.
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Electrification Of Vehicles Prompts BC Hydro's First Call For Power In 15 Years
BC Hydro Clean Power Call 2024 seeks utility-scale renewable energy, including wind and solar, to meet rising electricity demand, advance clean goals, expand grid, and support Indigenous participation through competitive procurement and equity opportunities.
Key Points
BC Hydro's 2024 bid to add zero-emission wind and solar to meet rising demand and support Indigenous equity.
✅ Competitive procurement for utility-scale wind and solar
✅ Targets 3,000 GWh new greenfield by fiscal 2029
✅ Encourages Indigenous ownership and equity stakes
The Government of British Columbia (the Government or Province) has announced that BC Hydro would be moving forward with a call for new sources of 100 percent clean, renewable emission-free electricity, notably including wind and solar, even as nuclear power remains a divisive option among residents. The call, expected to launch in spring 2024, is BC Hydro's first call for power in 15 years and will seek power from larger scale projects.
Over the past decade, British Columbia has experienced a growing economy and population as well as a move by the housing, business and transportation sectors towards electrification, with industrial demand from LNG facilities also influencing load growth. As the Government highlighted in their recent announcement, the number of registered light-duty electric vehicles in British Columbia increased from 5,000 in 2016 to more than 100,000 in 2023. Zero-emission vehicles represented 18.1 percent of new light-duty passenger vehicles sold in British Columbia in 2022, the highest percentage for any province or territory.
Ultimately, the Province now expects electricity demand in British Columbia to increase by 15 percent by 2030. BC Hydro elaborated on the growing need for electricity in their recent Signposts Update to the British Columbia Utilities Commission (BCUC), and noted additions such as new generating stations coming online to support capacity. BC Hydro implemented its Signposts Update process to monitor whether the "Near-term actions" established in its 2021 Integrated Resource Plan continue to be appropriate and align with the changing circumstances in electricity demand. Those actions outline how BC Hydro will meet the electricity needs of its customers over the next 20 years. The original Near-term actions focused on demand-side management and not incremental electricity production.
In its Update, BC Hydro emphasized that increased use of electricity and decreased supply, along with episodes of importing out-of-province fossil power during tight periods, has advanced the forecast of the province's need for additional renewable energy by three years. Accordingly, BC Hydro has updated its 2021 Integrated Resource Plan to, among other things:
accelerate the timing of several Near-term actions on energy efficiency, demand response, industrial load curtailment, electricity purchase agreement renewals and utility-scale batteries; and
add new Near-term actions for BC Hydro to acquire an additional 3,000 GWh per year of new clean, renewable energy from greenfield facilities in the province able to achieve commercial operation as early as fiscal 2029, as well as approximately 700 GWh per year of new clean, renewable energy from existing facilities prior to fiscal 2029.
The Province's predictions align with Canada Energy Regulator's (CER) "Canada's Energy Future 2023" flagship report (Report) released on June 20, 2023. The Report, which looks at Canadians' possible energy futures, includes two long-term scenarios modelled on Canada reaching net-zero by 2050. Under either scenario, the electricity sector is predicted to serve as the cornerstone of the net-zero energy system, with examples such as Hydro-Quebec's decarbonization strategy illustrating this shift as it transforms and expands to accommodate increasing electricity use.
Key Details of the Call
Though not finalized, the call for power will be a competitive process, with the exact details to be designed by BC Hydro and the Province, incorporating input from the recently-formed BC Hydro Task Force made up of Indigenous communities, industry and stakeholders. This is a shift from previous calls for power, which operated as a continuous-intake program with a standing offer at a fixed rate, after projects like the Siwash Creek project were left in limbo.
Drawing on advice from Indigenous and external energy experts, the Province seeks to advance Indigenous ownership and equity interest opportunities in the electricity sector, potentially with minimum requirements for Indigenous participation in new projects to be a condition of the competitive process. The Province has also committed $140 million to the B.C. Indigenous Clean Energy Initiative (BCICEI) to support Indigenous-led power projects and their ability to respond to future electricity demand, facilitating their ability to compete in the call for power, despite their smaller size.
BC Hydro expects to initiate the call in spring 2024, with the goal of acquiring new sources of electricity as early as 2028, even as clean electricity affordability features prominently in Ontario's election discourse.
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TC Energy confirms Ontario pumped storage project is advancing
Ontario Pumped Storage advances as Ontario's largest energy storage project, delivering clean electricity, long-duration capacity, and grid reliability for peak demand, led by TC Energy and Saugeen Ojibway Nation, with IESO review underway.
Key Points
A long-duration storage project in Meaford storing clean power for peak demand, supporting Ontario's emission-free grid.
✅ Stores clean electricity to power 1M homes for 11 hours
✅ Partnership: TC Energy and Saugeen Ojibway Nation
✅ Pending IESO review and OEB regulation decisions
In a bid to accelerate the province's ambitions for clean economic growth, TC Energy Corporation has announced significant progress in the development of the Ontario Pumped Storage Project. The Government of Ontario in Canada has unveiled a plan to address growing energy needs as a sustainable road map aimed at achieving an emission-free electricity sector, and as part of this plan, the Ministry of Energy is set to undertake a final evaluation of the proposed Ontario Pumped Storage Project. A decision is expected to be reached by the end of the year.
Ontario Pumped Storage is a collaborative effort between TC Energy and the Saugeen Ojibway Nation. The project is designed to be Ontario's largest energy storage initiative, capable of storing clean electricity to power one million homes for 11 hours. As the province strives to transition to a cleaner electricity grid by embracing clean power across sectors, long duration storage solutions like Ontario Pumped Storage will play a pivotal role in providing reliable, emission-free power during peak demand periods.
The success of the Project hinges on the approval of TC Energy's board of directors and a fruitful partnership agreement with the Saugeen Ojibway Nation. TC Energy is aiming for a final investment decision in 2024, as Ontario confronts an electricity shortfall in the coming years, with the anticipated in-service date being in the early 2030s, pending regulatory and corporate approvals.
“Ontario Pumped Storage will be a critical component of Ontario’s growing clean economy and will deliver significant benefits and savings to consumers,” said Corey Hessen, Executive Vice-President and President, TC Energy, Power and Energy Solutions. “Ontario continues to attract major investments that will have large power needs — many of which are seeking zero-emission energy before they invest. We are pleased the government is advancing efforts to recognize the significant role that long duration storage plays — firming resources, including new gas plants under provincial consideration, will become increasingly valuable in supporting a future emission-free electricity system.”
The Municipality of Meaford also expressed its support for the project, recognizing the positive impact it could have on the local economy and the overall electricity system of Ontario. Additionally, various stakeholders, including LiUNA OPDC, LiUNA Local 183, and the Ontario Chamber of Commerce, lauded the potential for job creation, training opportunities, and resilient energy infrastructure as Ontario seeks new wind and solar power to ease a coming electricity supply crunch.
The timeline for Ontario Pumped Storage's progress includes a final analysis by the Independent Electricity System Operator (IESO) to confirm its role in Ontario's electricity system and in balancing demand and emissions during the transition, to be completed by 30 September 2023. Concurrently, the Ministry of Energy will engage in consultations on the potential regulation of the Project via the Ontario Energy Board, while debates over clean, affordable electricity intensify ahead of the Ontario election, with a final determination scheduled for 30 November 2023.
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Ontario to seek new wind, solar power to help ease coming electricity supply crunch
Ontario Clean Grid Plan outlines emissions-free electricity growth, renewable energy procurement, nuclear expansion at Bruce and Darlington, reduced natural gas, grid reliability, and net-zero alignment to meet IESO demand forecasts and EV manufacturing loads.
Key Points
A plan to expand emissions-free power via renewables and nuclear, cut natural gas use, and meet growing demand.
✅ Targets renewables, hydro, and nuclear capacity growth
✅ Aims to reduce reliance on gas for grid reliability
✅ Aligns with IESO demand forecasts and EV manufacturing loads
Ontario is working toward filling all of the province’s quickly growing electricity needs with emissions-free sources, including a plan to secure new renewable generation and clean power options, but isn’t quite ready to commit to a moratorium on natural gas.
Energy Minister Todd Smith announced Monday a plan to address growing energy needs for 2030 to 2050 — the Independent Electricity System Operator projects Ontario’s electricity demand could double by mid-century — and next steps involve looking for new wind, solar and hydroelectric power.
“While we may not need to start building today, government and those in the energy sector need to start planning immediately, so we have new clean, zero-emissions projects ready to go when we need them,” Smith said in Windsor, Ont.
The strategy also includes two nuclear projects announced last week — a new large-scale nuclear plant at Bruce Power on the shore of Lake Huron and three new small modular reactors at the site of the Darlington nuclear plant east of Toronto.
Those projects, enough to power six million homes, will help Ontario end its reliance on natural gas to generate electricity, said Smith, but committing to a natural gas moratorium in 2027 and eliminating natural gas by 2050 is contingent on the federal government helping to speed up the new nuclear facilities.
“Today’s report, the Powering Ontario’s Growth plan, commits us to working towards a 100 per cent clean grid,” Smith said in an interview.
“Hopefully the federal government can get on board with our intentions to build this clean generation as quickly as possible … That will put us in a much better position to use our natural gas facilities less in the future, if we can get those new projects online.”
The IESO has said that natural gas is required to ensure supply and stability in the short to medium term, as Ontario works on balancing demand and emissions across the grid, but that it will also increase greenhouse gas emissions from the electricity sector.
The province is expected to face increased demand for electricity from expanded electric vehicle use and manufacturing in the coming years, even as a $400-billion cost estimate for greening the grid is debated.
Keith Brooks, programs director for Environmental Defence, said the provincial plan could have been much more robust, containing firm timelines and commitments.
“This plan does not commit to getting emissions out of the system,” he said.
“It doesn’t commit to net zero, doesn’t set a timeline for a net zero goal or have any projection around emissions from Ontario’s electricity sector going forward. In fact, it’s not really a plan. It doesn’t set out any real goals and it doesn’t it doesn’t project what Ontario’s supply mix might look like.”
The Canadian Climate Institute applauded the plan’s focus on reducing reliance on gas-fired generation and emphasizing non-emitting generation, but also said there are still some question marks.
“The plan is silent on whether the province intends to construct new gas-fired generation facilities,” even as new gas plant expansions are proposed, senior research director Jason Dion wrote in a statement.
“The province should avoid building new gas plants since cost-effective alternatives are available, and such facilities are likely to end up as stranded assets. The province’s timeline for reaching net zero generation is also unclear. Canada and other G7 countries have set a target for 2035, something Ontario will need to address if it wants to remain competitive.”
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Sudbury, Ont., eco groups say sustainability is key to grid's future
Sudbury Electrification and Grid Expansion is driving record power demand, EV charging, renewable energy planning, IESO forecasts, smart grid upgrades, battery storage, and industrial electrification, requiring cleaner power plants and transmission capacity in northern Ontario.
Key Points
Rising electricity demand and clean energy upgrades in Sudbury to power EVs, industry, and a smarter, expanded grid.
✅ IESO projects system size may need to more than double
✅ EVs and smart devices increase peak and off-peak load
✅ Battery storage and V2G can support reliability and resiliency
Sudbury, Ont., is consuming more power than ever, amid an electricity supply crunch in Ontario, according to green energy organizations that say meeting the demand will require cleaner energy sources.
"This is the welfare of the entire city on the line and they are putting their trust in electrification," said David St. Georges, manager of communications at reThink Green, a non-profit organization focused on sustainability in Sudbury.
According to St. Georges, Sudbury and northern Ontario can meet the growing demand for electricity to charge clean power for EVs and smart devices.
According to the Independent Electricity System Operator (IESO), making a full switch from fossil fuels to other renewable energy sources could require more power plants, while other provinces face electricity shortages of their own.
"We have forecasted that Ontario's electricity system will need significant expansion to meet this, potentially more than doubling in size," the IESO told CBC News in an emailed statement.
Electrification in the industrial sector is adding greater demand to the electrical grid as electric cars challenge power grids in many regions. Algoma Steel in Sault Ste. Marie and ArcelorMittal Dofasco in Hamilton both aim to get electric arc furnaces in operation. Together, those projects will require 630 megawatts.
"That's like adding four cities the size of Sudbury to the grid," IESO said.
Devin Arthur, chapter president of the Electric Vehicle society in Greater Sudbury, said the city is coming full circle with fully electrifying its power grid, reflecting how EVs are a hot topic in Alberta and beyond.
"We're going to need more power," he said.
"Once natural gas was introduced, that kind of switched back, and everyone was getting out of electrification and going into natural gas and other sources of power."
Despite Sudbury's increased appetite for electricity, Arthur added it's also easier to store now as Ontario moves to rely on battery storage solutions.
"What that means is you can actually use your electric vehicle as a battery storage device for the grid, so you can actually sell power from your vehicle that you've stored back to the grid, if they need that power," he said.
Harneet Panesar, chief operating officer for the Ontario Energy Board, told CBC the biggest challenge to going green is seeing if it can work around older infrastructure, while policy debates such as Canada's 2035 EV sales mandate shape the pace of change.
"You want to make sure that you're building in the right spot," he said.
"Consumers are shifting from combustion engines to EV drivetrains. You're also creating more dependency. At a very high level, I'm going to say it's probably going to go up in terms of the demand for electricity."
Fossil fuels are the first to go for generating electricity, said St. Georges.
"But we're not there yet, because it's not a light switch solution. It takes time to get to that, which is another issue of electrification," he said.
"It's almost impossible for us not to go that direction."
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Ontario announces SMR plans to four reactors at Darlington
Ontario Darlington SMR Expansion advances four GE Hitachi BWRX-300 reactors with OPG, adding 1,200 MW of baseload nuclear power to support electrification, grid reliability, and clean energy growth across Ontario and Saskatchewan.
Key Points
Plan to build four BWRX-300 SMRs at Darlington, delivering 1,200 MW of clean, reliable baseload power under OPG.
✅ Four GE Hitachi BWRX-300 units, 1,200 MW total
✅ Shared infrastructure cuts costs and timelines
✅ Supports electrification, grid reliability, net zero
The day after Ontario announced it would be building an additional 4,800 megawatts of nuclear reactors at Bruce Nuclear Generating Station, the province announced it would be dramatically expanding its planned rollout of small modular reactors at its Darlington Nuclear Generating Station, and confirmed plans to refurbish Pickering B as part of its broader strategy.
Ontario Power Generation OPG was always going to be the first to build the GE-Hitachi BWRX-300 small modular reactor SMR, with the U.S.’s Tennessee Valley Authority among others like SaskPower and several European nations following suit. But the OPG was originally going to build just one. On July 7, OPG and the Province of Ontario announced they would be bumping that up to four units of the BWRX-300.
The Ontario government is working with Ontario Power Generation (OPG) to commence planning and licensing for three additional small modular reactors (SMRs), for a total of four SMRs at the Darlington nuclear site. Once deployed, these four units would produce a total 1,200 megawatts (MW) of electricity, equivalent to powering 1.2 million homes, helping to meet increasing demand from electrification and fuel the province’s strong economic growth, the Ontario Ministry of Energy said in a release.
“Our government’s open for business approach has led to unprecedented investments across the province — from electric vehicles and battery manufacturing to critical minerals to green steel,” said Todd Smith, Minister of Energy. “Expanding Ontario’s world-leading SMR program will ensure we have the reliable, affordable and clean electricity we need to power the next major international investment, the new homes we are building and industries as they grow and electrify.”
For the first time since 2005, Ontario’s electricity demand is rising. While the government has implemented its plan to meet rising electricity demand this decade, the experts at Ontario’s Independent Electricity System Operator have recommended the province advance new nuclear generation and pursue life-extension at Pickering NGS to provide reliable, baseload power to meet increasing electricity needs in the 2030s and beyond.
Subject to Ontario Government and Canadian Nuclear Safety Commission (CNSC) regulatory approvals on construction, the additional SMRs could come online between 2034 and 2036. That is the same timeframe that SaskPower is looking at for its first, and possibly second, units.
The initial unit is expected to go online in 2028 following Ontario’s first SMR groundbreaking at Darlington.
The Darlington site, which already hosts four reactors, was originally considered for an expansion of “large nuclear,” which is why OPG was already well on its way for site approvals of additional nuclear power generation. The plan changed to one, singular, SMR. Now that has been updated to four.
The announcement has significant impact on Saskatchewan, and its plans to build four of its own SMRs. The timing would allow Ontario Power Generation to apply learnings from the construction of the first unit to deliver cost savings on subsequent units. This is also the strategy SaskPower is following – allow Ontario to build the first, then learn from that experience.
Building multiple units will also allow common infrastructure such as cooling water intake, transmission connection and control room to be utilized by all four units instead of just one, reducing costs even further, the Ministry said.
“A fleet of SMRs at the Darlington New Nuclear Site is key to meeting growing electricity demands and net zero goals,” said Ken Hartwick, OPG President and CEO. “OPG has proven its large nuclear project expertise through the on-time, on budget Darlington Refurbishment project. By taking a similar approach to building a fleet of SMRs, we will deliver cost and schedule savings, and power 1.2 million homes from this site by the mid-2030s.”
The Darlington SMR project is situated on the traditional and treaty territories of the seven Williams Treaties First Nations and is also located within the traditional territory of the Huron Wendat peoples. OPG is actively engaging and consulting with potentially impacted Indigenous communities, including exploring economic opportunities in the Darlington SMR project such as commercial participation and employment.
The Ministry noted, “Ontario’s robust nuclear supply chain is uniquely positioned to support SMR development and deployment in Ontario, Canada and globally. Building additional SMRs at Darlington would provide more opportunities for Ontario companies and broader economic benefits as suppliers of nuclear equipment, components, and services to make further investments to expand their operation to serve the growing SMR market both domestically and abroad.”
Supporting new SMR development and investing in nuclear power is part of the Ontario government’s larger plan, aligned with a Canadian interprovincial nuclear initiative that brings provinces together, to prepare for electricity demand in the 2030s and 2040s that will build on Ontario’s clean electricity advantage and ensure the province has the power to maintain it’s position as leader in job creation and a magnet for the industries of the future, the Ministry said.
In February, World Nuclear News (WNN) reported that Poland was considering up to 79 small modular reactors of the same design as OPG and SaskPower. And on June 5, it reported, “Canada’s Ontario Power Generation will provide operator services to Poland’s Orlen Synthos Green Energy under a letter of intent signed between the partners, extending their existing cooperation on the deployment of small modular reactors.”
WNN added, “The letter of intent is aimed at concluding future agreements under which OPG and its subsidiaries could provide operator services for SMR reactors to OSGE in connection with the deployment of SMRs in Poland and other European countries. The partnership would include a number of SMR-related activities including: development and deployment; operations and maintenance; operator training; commissioning; and regulatory support.”
