Electricity News in March 2023
Potent greenhouse gas declines in the US, confirming success of control efforts
US SF6 Emissions Decline as NOAA analysis and EPA mitigation show progress, with atmospheric measurements and Greenhouse Gas Reporting verifying reductions from the electric power grid; sulfur hexafluoride's extreme global warming potential underscores inventory improvements.
Key Points
A documented drop in US sulfur hexafluoride emissions, confirmed by NOAA atmospheric data and EPA reporting reforms.
✅ NOAA towers and aircraft show 2007-2018 decline
✅ EPA reporting and utility mitigation narrowed inventory gaps
✅ Winter leaks and servicing signal further reduction options
A new NOAA analysis shows U.S. emissions of the super-potent greenhouse gas sulfur hexafluoride (SF6) have declined between 2007-2018, likely due to successful mitigation efforts by the Environmental Protection Agency (EPA) and the electric power industry, with attention to SF6 in the power industry across global markets.
At the same time, significant disparities that existed previously between NOAA’s estimates, which are based on atmospheric measurements, and EPA’s estimates, which are based on a combination of reported emissions and industrial activity, have narrowed following the establishment of the EPA's Greenhouse Gas Reporting Program. The findings, published in the journal Atmospheric Chemistry and Physics, also suggest how additional emissions reductions might be achieved.
SF6 is most commonly used as an electrical insulator in high-voltage equipment that transmits and distributes electricity, and its emissions have been increasing worldwide as electric power systems expand, even as regions hit milestones like California clean energy surpluses in recent years. Smaller amounts of SF6 are used in semiconductor manufacturing and in magnesium production.
SF6 traps 25,000 times more heat than carbon dioxide over a 100-year time scale for equal amounts of emissions, and while CO2 emissions flatlined in 2019 globally, that comparison underscores the potency of SF6. That means a relatively small amount of the gas can have a significant impact on climate warming. Because of its extremely large global warming potential and long atmospheric lifetime, SF6 emissions will influence Earth’s climate for thousands of years.
In this study, researchers from NOAA’s Global Monitoring Laboratory, as record greenhouse gas concentrations drive demand for better data, working with colleagues at EPA, CIRES, and the University of Maryland, estimated U.S. SF6 emissions for the first time from atmospheric measurements collected at a network of tall towers and aircraft in NOAA’s Global Greenhouse Gas Reference Network. The researchers provided an estimate of SF6 emissions independent from the EPA’s estimate, which is based on reported SF6 emissions for some industrial facilities and on estimated SF6 emissions for others.
“We observed differences between our atmospheric estimates and the EPA’s activity-based estimates,” said study lead author Lei Hu, a Global Monitoring Laboratory researcher who was a CIRES scientist at the time of the study. “But by closely collaborating with the EPA, we were able to identify processes potentially responsible for a significant portion of this difference, highlighting ways to improve emission inventories and suggesting additional emission mitigation opportunities, such as forthcoming EPA carbon capture rules for power plants, in the future.”
In the 1990s, the EPA launched voluntary partnerships with the electric power, where power-sector carbon emissions are falling as generation shifts, magnesium, and semiconductor industries to reduce SF6 emissions after the United States recognized that its emissions were significant. In 2011, large SF6 -emitting facilities were required to begin tracking and reporting their emissions under the EPA Greenhouse Gas Reporting Program.
Hu and her colleagues documented a decline of about 60 percent in U.S. SF6 emissions between 2007-2018, amid global declines in coal-fired power in some years—equivalent to a reduction of between 6 and 20 million metric tons of CO2 emissions during that time period—likely due in part to the voluntary emission reduction partnerships and the EPA reporting requirement. A more modest declining trend has also been reported in the EPA’s national inventories submitted annually under the United Nations Framework Convention on Climate Change.
Examining the differences between the NOAA and EPA independent estimates, the researchers found that the EPA’s past inventory analyses likely underestimated SF6 emissions from electrical power transmission and distribution facilities, and from a single SF6 production plant in Illinois. According to Hu, the research collaboration has likely improved the accuracy of the EPA inventories. The 2023 draft of the EPA’s U.S. Greenhouse Gas Emissions and Sinks: 1990-2021 used the results of this study to support revisions to its estimates of SF6 emissions from electrical transmission and distribution.
The collaboration may also lead to improvements in the atmosphere-based estimates, helping NOAA identify how to expand or rework its network to better capture emitting industries or areas with significant emissions, according to Steve Montzka, senior scientist at GML and one of the paper’s authors.
Hu and her colleagues also found a seasonal variation in SF6 emissions from the atmosphere-based analysis, with higher emissions in winter than in summer. Industry representatives identified increased servicing of electrical power equipment in the southern states and leakage from aging brittle sealing materials in the equipment in northern states during winter as likely explanations for the enhanced wintertime emissions—findings that suggest opportunities for further emissions reductions.
“This is a great example of the future of greenhouse gas emission tracking, where inventory compilers and atmospheric scientists work together to better understand emissions and shed light on ways to further reduce them,” said Montzka.
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Wind, solar, batteries make up 82% of 2023 utility-scale US pipeline
US Renewable Energy Capacity 2023 leads new utility-scale additions, with solar, wind, and battery storage surging; EIA data cite tax incentives, lower costs, and smart grid upgrades driving grid reliability and decarbonization.
Key Points
In 2023, renewables dominate new US utility-scale capacity: 54% solar, 7.1 GW wind, 8.6 GW battery storage, per EIA.
✅ 54% of 2023 US additions are solar, a record year
✅ 7.1 GW wind and 8.6 GW batteries expand grid resources
✅ Storage, smart grids, incentives boost reliability and growth
Wind, solar, and batteries make up 82% of 2023’s expected new utility-scale power capacity in the US, highlighting wind power's surge alongside solar and storage, according to the US Energy Information Administration’s (EIA) “Preliminary Monthly Electric Generator Inventory.”
As of January 2023, the US was operating 73.5 gigawatts (GW) of utility-scale solar capacity, which aligns with rising solar generation trends across the US – about 6% of the country’s total.
But solar makes up just over half of new US generating capacity expected to come online in 2023, supported by favourable government plans across key markets. And if it all goes as expected, it will be the most solar capacity added in a single year in the US. It will also be the first year that more than half of US capacity additions are solar, underscoring solar's No. 3 renewable ranking in the U.S. mix.
As of January 2023, 141.3 GW of wind capacity was operating in the US, reflecting wind's status as the most-used renewable nationwide – about 12% of the US total. Another 7.1 GW are planned for 2023. Tax incentives, lower wind turbine construction costs, and new renewable energy targets are spurring the growth.
And developers also plan to add 8.6 GW of battery storage power capacity to the grid this year, supporting record solar and storage buildouts across the market, and that’s going to double total US battery power capacity.
However, differences in the amount of electricity that different types of power plants can produce mean that wind and solar made up about 17% of the US’s utility-scale capacity in 2021, but produced 12% of electricity, even as renewables surpassed coal nationally in 2022. Solutions such as energy storage, smart grids, and infrastructure development will help bridge that gap.
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How much does it cost to charge an electric vehicle? Here's what you can expect.
Electric Vehicle Charging Costs and Times explain kWh usage, electricity rates, Level 2 vs DC fast charging, per-mile expense, and tax credits, with examples by region and battery size to estimate home and public charging.
Key Points
They measure EV charging price and duration based on kWh rates, charger level, efficiency, and location.
✅ Costs vary by kWh price, region, and charger type.
✅ Efficiency (mi/kWh) sets per-mile cost and range.
✅ Tax credits and utility rates impact total ownership.
More and more car manufacturing companies dip their toes in the world of electric vehicles every year, making it a good time to buy an EV for many shoppers, and the U.S. government is also offering incentives to turn the tides on car purchasing. Electric vehicles bought between 2010 and 2022 may be eligible for a tax credit of up to $7,500.
And according to the Consumer Reports analysis on long-term ownership, the cost of charging an electric vehicle is almost always cheaper than fueling a gas-powered car – sometimes by hundreds of dollars.
But that depends on the type of car and where in the country you live, in a market many expect to be mainstream within a decade across the U.S. Here's everything you need to know.
How much does it cost to charge an electric car?
An electric vehicle’s fuel efficiency can be measured in kilowatt-hours per 100 miles, and common charging-efficiency myths have been fact-checked to correct math errors.
For example, if electricity costs 10.7 cents per kilowatt-hour, charging a 200-mile range 54-kWh battery would cost about $6. Charging a vehicle that consumes 27 kWh to travel 100 miles would cost three cents a mile.
The national average cost of electricity is 10 cents per kWh and 11.7 cents per kWh for residential use. Idaho National Laboratory’s Advanced Vehicle Testing compares the energy cost per mile for electric-powered and gasoline-fueled vehicles.
For example, at 10 cents per kWh, an electric vehicle with an efficiency of 3 miles per kWh would cost about 3.3 cents per mile. The gasoline equivalent cost for this electricity cost would be just under $2.60 per gallon.
Prices vary by location as well. For example, Consumer Report found that West Coast electric vehicles tend to be less expensive to operate than gas-powered or hybrid cars, and are often better for the planet depending on local energy mix, but gas prices are often lower than electricity in New England.
Public charging networks in California cost about 30 cents per kWh for Level 2 and 40 cents per kWh for DCFC. Here’s an example of the cost breakdown using a Nissan LEAF with a 150-mile range and 40-kWh battery:
Level 2, empty to full charge: $12
DCFC, empty to full charge: $16
Many cars also offer complimentary charging for the first few years of ownership or provide credits to use for free charging. You can check the full estimated cost using the Department of Energy’s Vehicle Cost Calculator as the grid prepares for an American EV boom in the years ahead.
How long does it take to charge an electric car?
This depends on the type of charger you're using. Charging with a Level 1 charger takes much longer to reach full battery than a level 2 charger or a DCFC, or Direct Current Fast Charger. Here's how much time you can expect to spend charging your electric vehicle:
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A new nuclear reactor in the U.S. starts up. It's the first in nearly seven years
Vogtle Unit 3 Initial Criticality marks the startup of a new U.S. nuclear reactor, initiating fission to produce heat, steam, and electricity, supporting clean energy goals, grid reliability, and carbon-free baseload power.
Key Points
Vogtle Unit 3 Initial Criticality is the first fission startup, launching power generation at a new U.S. reactor.
✅ First new U.S. reactor to reach criticality since 2016
✅ Generates carbon-free baseload power for the grid
✅ Faced cost overruns and delays during construction
For the first time in almost seven years, a new nuclear reactor has started up in the United States.
On Monday, Georgia Power announced that the Vogtle nuclear reactor Unit 3 has started a nuclear reaction inside the reactor as part of the first new reactors in decades now taking shape at the plant.
Technically, this is called “initial criticality.” It’s when the nuclear fission process starts splitting atoms and generating heat, Georgia Power said in a written announcement.
The heat generated in the nuclear reactor causes water to boil. The resulting steam spins a turbine that’s connected to a generator that creates electricity.
Vogtle’s Unit 3 reactor will be fully in service in May or June, Georgia Power said.
The last time a nuclear reactor reached the same milestone was almost seven years ago in May 2016 when the Tennessee Valley Authority started splitting atoms at the Watts Bar Unit 2 reactor in Tennessee, Scott Burnell, a spokesperson for the Nuclear Regulatory Commission, told CNBC.
“This is a truly exciting time as we prepare to bring online a new nuclear unit that will serve our state with clean and emission-free energy for the next 60 to 80 years,” Chris Womack, CEO of Georgia Power, said in a written statement.
Including the newly turned-on Vogtle Unit 3 reactor, there are currently 93 nuclear reactors operating in the United States and, collectively, they generate 20% of the electricity in the country, although a South Carolina plant leak recently showed how outages can sideline a unit for weeks.
Nuclear reactors, which help combat global warming and support net-zero emissions goals, generate about half of the clean, carbon-free electricity generated in the U.S.
Most of the nuclear power reactors in the United States were constructed between 1970 and 1990, but construction slowed significantly after the accident at Three Mile Island near Middletown, Pennsylvania, on March 28, 1979, even as interest in next-gen nuclear power has grown in recent years. From 1979 through 1988, 67 nuclear reactor construction projects were canceled, according to the U.S. Energy Information Administration.
However, because nuclear energy is generated without releasing carbon dioxide emissions, which cause global warming, the increased sense of urgency in responding to climate change has given nuclear energy a chance at a renaissance as atomic energy heats up again globally.
The cost associated with building nuclear reactors is a major barrier to a potential resurgence in nuclear energy, however, even as nuclear generation costs have fallen to a ten-year low. And the new builds at Vogtle have become an epitome of that charge: The construction of the two Vogtle reactors has been plagued by cost overruns and delays.
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Solar produced 4.7% of U.S. electricity in 2022, generation up 25%
US Solar Electricity Generation 2022 rose to a 4.7% share, with 202,256 GWh, per EIA Electric Power Monthly; driven by PV capacity additions despite import constraints, alongside renewables trends in wind, nuclear, and hydroelectric output.
Key Points
The share and output of US solar PV in 2022: 4.7% of electricity and 202,256 GWh, as reported by the EIA.
✅ Solar PV reached 4.7% of US power; 202,256 GWh generated in 2022.
✅ Monthly share varied from about 3% in Jan to just over 6% in Apr.
✅ Wind was 10.1%; wind+solar hit slightly over 20% in April.
In 2022, solar photovoltaics made up 4.7% of U.S. electricity generation, an increase of almost 21% over the 2021 total when solar produced 3.9% of US electricity and about 3% in 2020 according to long-term outlooks. Total solar generation was up 25%, breaking through 200,000 GWh for the year.
The record deployment volumes of 2020 when renewables became the second-most U.S. electricity source and 2021 are the main factors behind this increase. If it were not for ongoing solar panel import difficulties and general inflation, solar’s contribution to electricity generation might have reached 5% in 2022. The data was released by the Department of Energy’s Energy Information Administration (EIA) in their Electric Power Monthly. This release includes data from December 2022, as well as the rest of the data from 2022.
Solar as a percentage of monthly electricity generation ranged from a low of almost 3% in January, to just over 6% in April. April’s production marked a new monthly record for solar generation in the US and coincided with a renewables share record that month.
Total generation of solar electricity peaked in July, at 21,708 GWh. Over the course of the year, solar production reached 202,256 GWh, and total U.S. electricity generation reached 4,303,980 GWh, a year in which renewables surpassed coal in the power mix overall. Total US electricity generation increased by 3.5% over the 4,157,467 GWh produced in 2021.
In 2022, wind energy contributed 10.1% of the total electricity generated in the United States. Wind and solar together produced 14.8% of U.S. electricity in 2022, growing from the 13% recorded in 2021. In April, when solar power peaked at just over 6%, wind and solar power together reached a peak of slightly over 20%, as a wind-and-solar milestone versus nuclear was noted that month, a new monthly record for the two energy sources.
In total, emissions free energy sources such as wind, solar photovoltaic and thermal, nuclear, hydroelectric, and geothermal, accounted for 37.9% of the total electricity generated in the U.S., while renewables provided about 25.5% share of the mix during the year. This value is barely higher than 2020’s 37.7% – but represents a return to growth after 2021 saw a decrease in emission free electricity to 37%.
Nuclear power was the most significant contributor to emission free electricity, making up a bit more than 45% of the total emissions free electricity. Wind energy ranked second at 26%, followed by hydroelectricity at 15%, and solar photovoltaic at 12%, confirming solar as the #3 renewable in the U.S. mix.
Emissions free electricity is a different summation than the EIA’s ‘Renewable Energy’ category. The Renewable Energy category also includes:
- Wood and Wood-Derived Fuels
- Landfill Gas
- Biogenic Municipal Solid Waste
- Other Waste Biomass
Nuclear produced 17.9% of the total U.S. electricity, a value that has generally stayed flat over the years. However, since nuclear facilities are being retired faster than new facilities are coming online, nuclear production has fallen in the past two years. After multiple long delays, we will probably see reactor three of the Vogtle nuclear facility come online in 2023. Reactor four is officially scheduled to come online later this year.
Hydroelectric production also declined in 2022, due to drought conditions in the southwestern United States. With rain and snow storms in California and the southwest, hydroelectricity generation may rebound in 2023.
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State-owned electricity generation firm could save Britons nearly 21bn a year?
Great British Energy could cut UK electricity costs via public ownership, investing in clean energy like wind, solar, tidal, and nuclear, curbing windfall profits, stabilizing bills, and reinvesting returns through a state-backed generator.
Key Points
A proposed state-backed UK generator investing in clean power to cut costs and return gains to taxpayers.
✅ Publicly owned investment in wind, solar, tidal, and nuclear
✅ Cuts electricity bills by reducing generators' windfall profits
✅ Funded via bonds or asset buyouts; non-profit operations
A publicly owned electricity generation firm could save Britons nearly £21bn a year, according to new analysis that bolsters Labour’s case to launch a national energy company if the party gains power.
Thinktank Common Wealth has calculated that the cost of generating electricity to power homes and businesses could be reduced by £20.8bn or £252 per household a year under state ownership, according to a report seen by the Guardian.
The Labour leader, Keir Starmer, has committed to creating “a publicly owned national champion in clean energy” named Great British Energy.
Starmer is yet to lay out the exact structure of the mooted company, although he has said it would not involve nationalising existing assets, or become involved in the transmission grid or retail supply of energy.
Starmer instead hopes to create a state-backed entity that would invest in clean energy – wind, solar, tidal, nuclear, large-scale storage and other emerging technologies – creating jobs and ensuring windfalls from the growth in low carbon power feed back to the government.
The Common Wealth report, which analysed scenarios for reforming the electricity market, said that a huge saving on electricity costs could be made by buying out assets such as wind, solar and biomass generators on older contracts and running them on a non-profit basis. Funding the measure could require a government bond issuance, or some form of compulsory purchase process.
Last year the government attempted to get companies operating low carbon generators, including nuclear power plants, on older contracts to switch to contracts for difference (CfD), allowing any outsized profits to flow back to taxpayers. However, the government later decided to tax eligible firms through the electricity generator levy instead.
The Common Wealth study concluded that a publicly owned low carbon energy generator would best deliver on Britain’s climate and economic goals, would eliminate windfall profits made by generators and would cut household bills significantly.
MPs and campaigners have argued that Britain’s energy companies should be nationalised since the energy crisis, even as coal-free records have multiplied and renewables still need more support, which has resulted in North Sea oil and gas producers and electricity generators making windfall profits, and a string of retail suppliers collapsing, costing taxpayers billions. Detractors of nationalisation in energy argue it can stifle innovation and expose taxpayers to huge financial risks.
Common Wealth pointed out that more than 40% of the UK’s offshore wind generation capacity was publicly owned by overseas national entities, meaning the benefits of high electricity prices linked to the war in Ukraine had flowed back to other governments.
The study found the publicly owned generator model would create more savings than other options, including a drive for voluntary CfDs; splitting the generation market between low carbon and fossil fuel sources at a time when wind and solar have outproduced nuclear, and a “single buyer model” with nationalised retail suppliers.
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Ukraine has electricity reserves, no more outages planned if no new strikes
Ukraine Electricity Outages may pause as the grid stabilizes, with energy infrastructure repairs, generators, and reserves supporting supply; officials cite no rationing absent new Russian strikes, while Odesa networks recover and Ukrenergo completes restoration works.
Key Points
Planned power cuts in Ukraine paused as grid capacity, repairs, and reserves improve, barring new strikes.
✅ No rationing if Russia halts strikes on energy infrastructure
✅ Grid repairs and reserves meet demand for third straight week
✅ Odesa networks restored; Ukrenergo crews redeploy to repairs
Ukraine plans no more outages to ration electricity if there are no new strikes and has been able to amass some power reserves, the energy minister said on Saturday, as it continues to keep the lights on despite months of interruptions caused by Russian bombings.
"Electricity restrictions will not be introduced, provided there are no Russian strikes on infrastructure facilities," Energy Minister Herman Halushchenko said in remarks posted on the ministry's Telegram messaging platform.
"Outages will only be used for repairs."
After multiple battlefield setbacks and scaling down its troop operation to Ukraine's east and south, Russia in October began bombing the country's energy infrastructure, as winter loomed over the battlefront, leaving millions without power and heat for days on end.
The temperature in winter months often stays below freezing across most of Ukraine. Halushchenko said this heating season has been extremely difficult.
"But our power engineers managed to maintain the power system, and for the third week in a row, electricity generation has ensured consumption needs, we have reserves," Halushchenko said.
Ukraine, which does not produce power generators itself, has imported and received thousands of them over the past few years, with the U.S. pledging a further $10 billion on Friday to aid Kyiv's energy needs, despite ended grid restoration support reported earlier.
Separately, the chief executive of state grid operator Ukrenergo, Volodymyr Kudrytskyi, said that repair works on the damaged infrastructure in the city of Odesa suffered earlier this month, has been finished, highlighting how Ukraine has even helped Spain amid blackouts while managing its own network challenges.
"Starting this evening, there is more light in Odesa," Kudrytskyi wrote on his Facebook page. "The crews that worked on restoring networks are moving to other facilities."
A Feb. 4 fire that broke out at an overloaded power station left hundreds of thousands of residents without electricity, prompting many to adopt new energy solutions to cope with outages.
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Explainer: Europe gets ready to revamp its electricity market
EU Electricity Market Reform seeks to curb gas-driven volatility by expanding CfDs and PPAs, decoupling power from gas, and aligning consumer bills with low-cost renewables and nuclear, as Brussels advances market redesign.
Key Points
An EU plan to curb price spikes by expanding long-term contracts and tying bills to cheap renewables.
✅ Expands CfDs and PPAs to lock in predictable power prices
✅ Aims to decouple bills from gas-driven wholesale volatility
✅ Seeks investment certainty for renewables, nuclear, and grids
European Union energy ministers meet on Monday to debate upcoming power market reforms. Brussels is set to propose the revamp next month, but already countries are split over how to "fix" the energy system - or whether it needs fixing at all.
Here's what you need to know.
POST-CRISIS CHANGES
The European Commission pledged last year to reform the EU's electricity market rules, after record-high gas prices - caused by cuts to Russian gas flows - sent power prices soaring during an energy crisis for European companies and citizens.
The aim is to reform the electricity market to shield consumer energy bills from short-term swings in fossil fuel prices, and make sure that Europe's growing share of low-cost renewable electricity translates into lower prices, even though rolling back electricity prices poses challenges for policymakers.
Currently, power prices in Europe are set by the running cost of the plant that supplies the final chunk of power needed to meet overall demand. Often, that is a gas plant, so gas price spikes can send electricity prices soaring.
EU countries disagree on how far the reforms should go.
Spain, France and Greece are among those seeking a deep reform.
In a document shared with EU countries, seen by Reuters, Spain said the reforms should help national regulators to sign more long-term contracts with electricity generators to pay a fixed price for their power.
Nuclear and renewable energy producers, for example, would receive a "contract for difference" (CfD) from the government to provide power during their lifespan - potentially decades - at a stable price that reflects their average cost of production.
Similarly, France suggests, as part of a new electricity pricing scheme, requiring energy suppliers to sign long-term, fixed-price contracts with power generators - either through a CfD, or a private Power Purchase Agreement (PPA) between the parties.
French officials say this would give the power plant owner predictable revenue, while enabling consumers to have part of their energy bill comprised of this more stable price.
Germany, Denmark, Latvia and four other countries oppose a deep reform, and, as nine EU countries oppose reforms overall, have warned the EU against a "crisis mode" overhaul of a complex system that has taken decades to develop.
They say Europe's existing power market is functioning well, and has fostered years of lower power prices, supported renewable energy and helped avoid energy shortages.
Those countries support only limited tweaks, such as making it easier for consumers to choose between fluctuating and fixed-price power contracts.
'DECOUPLE' PRICES?
The Commission initially pitched the reform as a chance to "decouple" gas and power prices in Europe, suggesting a redesign of the current system of setting power prices. But EU officials say Brussels now appears to be leaning towards more modest changes.
A public consultation on the reforms last month steered clear of a deep energy market intervention. Rather, it suggested expanding Europe's use of long-term contracts, outlining a plan for more fixed-price contracts that provide power plants with a fixed price for their electricity, like CfDs or PPAs.
The Commission said this could be done by setting EU-wide rules for CfDs and letting countries voluntarily use them, or require new state-funded power plants to sign CfDs. The consultation mooted the idea of forcing existing power plants to sign CfDs, but said this could deter much-needed investments in renewable energy.
RISKS, REWARDS
Pro-reform countries like Spain say a revamped power market will bring down energy prices for consumers, by matching their bills more closely with the true cost of producing lower-carbon electricity.
France says the aim is to secure investment in low-carbon energy including renewables, and nuclear plants like those Paris plans to build. It also says lowering power prices should be part of Europe's response to massive industrial subsidies in the United States and China - by helping European firms keep a competitive edge.
But sceptics warn that drastic changes to the market could knock confidence among investors, putting at risk the hundreds of billions of euros in renewable energy investments the EU says are needed to quit Russian fossil fuels under its plan to dump Russian energy and meet climate goals.
Energy companies including Engie (ENGIE.PA), Orsted (ORSTED.CO) and Iberdrola (IBE.MC) have said making CfDs mandatory or imposing them retroactively on existing power plants could deter investment and trigger litigation from energy companies.
POLITICAL DEBATE
EU countries' energy ministers discuss the reforms on Monday, before formal negotiations begin.
The Commission, which drafts EU laws, plans to propose the reforms on Mar. 14. After that, EU countries and lawmakers negotiate the final law, which must win majority support from European Parliament lawmakers and a reinforced majority of at least 15 countries.
Negotiations on major EU legislation often take more than a year, but some countries are pushing for a fast-tracked deal. France wants the law to be finished this year.
That has already hit resistance from countries like Germany, highlighting a France-Germany tussle over the scope of reform as they say deeper changes cannot be rushed through, and they would need an "in-depth impact assessment" - something the Commission's upcoming proposal is not expected to include, because it has been drafted so quickly.
The timeline is further complicated by European Parliament elections in 2024. That has raised concerns in reform-hungry states that failure to strike a deal before the election could significantly delay the reforms, if negotiations have to pause until a new EU parliament is elected.
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Wind and solar power generated more electricity in the EU last year than gas. Here's how
EU Renewable Energy Transition accelerates as solar and wind overtake gas, cutting coal reliance and boosting REPowerEU goals; falling electricity demand, hydro and nuclear recovery, and grid upgrades drive a cleaner, secure power mix.
Key Points
It is the EU's shift to solar and wind, surpassing gas and curbing coal to meet REPowerEU targets.
✅ Solar and wind supplied 22% of EU electricity in 2022.
✅ Gas fell behind; coal stayed near 16% with no major rebound.
✅ Demand fell; hydro and nuclear expected to recover in 2023.
European countries were forced to accelerate their renewable energy capacity after Russia's invasion of Ukraine sparked a global energy crisis amid a surge in global power demand that exceeded pre-pandemic levels. The EU’s REPowerEU plan aims to increase the share of renewables in final energy consumption overall to 45 percent by the end of the decade.
However, a new report by energy think tank Ember shows that the EU’s green energy transition is already making a significant difference. Solar and wind power generated more than a fifth (22 percent) of its electricity in 2022, pulling ahead of fossil gas (20 percent) for the first time, according to the European Electricity Review 2023.
Europe also managed to avoid resorting to emissions-intensive coal power for electricity generation as a consequence of the energy crisis, even as renewables to eclipse coal globally by mid-decade. Coal generated just 16 percent of the EU’s electricity last year, an increase of just 1.5 percentage points.
“Europe has avoided the worst of the energy crisis,” says Ember’s Head of Data Insights, Dave Jones. “The shocks of 2022 only caused a minor ripple in coal power and a huge wave of support for renewables. Any fears of a coal rebound are now dead.”
Ember’s analysis reveals that the EU faced a "triple crisis" in the electricity sector in 2022, as stunted hydro and nuclear output compounded the shock. "Just as Europe scrambled to cut ties with its biggest supplier of fossil gas, it faced the lowest levels of hydro and nuclear (power) in at least two decades, which created a deficit equal to 7 percent of Europe’s total electricity demand in 2022," the report says. A severe drought across Europe, French nuclear outages as well as the closure of German nuclear outlets were responsible for the drop.
Solar power shines through
However, the record surge in solar and wind power generation helped compensate for the nuclear and hydropower deficit. Solar power rose the fastest, growing by a record 24 percent last year which almost doubled its previous record, with wind growing by 8.6 percent.
Forty-one gigawatts of solar power capacity was added in 2022, almost 50 percent more than the year before. Ember says that 20 EU countries achieved solar records in 2022, with Germany, Spain, Poland, the Netherlands and France adding the most solar capacity.
The Netherlands and Greece generated more power from solar than coal for the first time. Greece is also predicted to reach its 2030 solar capacity target by the end of this year.
EU electricity demand falls
A significant drop in electricity use in 2022 also helped lessen the impact of Europe’s energy crisis. Demand fell by 7.9 percent in the last quarter of the year, despite the continent heading into winter. This was close to the 9.6 percent fall experienced when Europe was in Covid-19 lockdown in mid-2020.
"Mild weather was a deciding factor, but affordability pressures likely played a role, alongside energy efficiency improvements and citizens acting in solidarity to cut energy demand in a time of crisis," the report says.
A ‘coal comeback’ fails to materialize
The almost 8 percent fall in electricity demand in the last three months of 2022 was the main factor in the 9 percent fall in gas and coal generation during that time. However, Ember says that had France’s nuclear plants been operating at the same capacity as 2021, the EU’s fossil fuel generation would have fallen twice as fast in the last quarter of 2022.
The report says: "Coal power in the EU fell in all four of the final months of 2022, down 6 percent year-on-year. The 26 coal units placed on emergency standby for winter ran at an average of just 18 percent capacity. Despite importing 22 million tonnes of extra coal throughout 2022, the EU only used a third of it."
Gas generation was very similar compared to 2021, up just 0.8 percent. It made up 20 percent of the EU electricity mix in 2022, up from 19 percent the year before.
Fossil fuel generation set to fall in 2023
Ember says low-emissions sources like solar and wind power will continue to accelerate in 2023 and hydropower and French nuclear capacity will also recover. With electricity demand likely to continue to fall, it estimates that fossil fuel-generation "could plummet" by 20 percent in 2023.
Gas generation will fall the fastest, Ember predicts, as it will remain more expensive than coal over the next few years. "The large fall in gas generation means the power sector is likely to be the fastest falling segment of gas demand during 2023, helping to bring calm to European gas markets as Europe adjusts to life without Russian gas."
In order to stick to the 2015 Paris Agreement target of limiting global warming to no more than 1.5 degrees Celsius compared to pre-industrial levels, Ember says Europe must fully decarbonize its power system by the mid-2030s. Its modeling shows that this is possible without compromising the security of supply.
However, the report says "making this vision a reality will require investment above and beyond existing plans, as well as immediate action to address barriers to the expansion of clean energy infrastructure. Such a mobilization would boost the European economy, cement the EU’s position as a climate leader and send a vital international message that these challenges can be overcome."
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EU draft shows plan for more fixed-price electricity contracts
EU Electricity Market Reform advances two-way CfDs, PPAs, and fixed-price tariffs to cut volatility, support renewables and nuclear, stabilize investor revenues, and protect consumers from price spikes across wholesale power markets.
Key Points
An EU plan expanding two-way CfDs, PPAs, and fixed-price contracts to curb price swings and support low-carbon power.
✅ Two-way CfDs return excess revenues to consumers
✅ Boosts PPAs and fixed-price retail options
✅ Targets renewables, nuclear; limits fossil exposure
The European Union wants to expand the use of contracts that pay power plants a fixed price for electricity, a draft proposal showed, as part of an electricity market revamp to shield European consumers from big price swings.
The European Commission pledged last year to reform the EU's electricity market rules, after record-high gas prices, caused by cuts to Russian flows, sent power prices soaring, prompting debates over gas price cap strategies in response.
A draft of the EU executive's proposal, seen by Reuters on Tuesday and due to be published on Mar. 16, steered clear of the deep redesign of the electricity market that some member states have called for, even as nine EU countries opposed sweeping reforms as a fix earlier in the crisis, suggesting instead limited changes to nudge countries towards more predictable, fixed-price power contracts.
If EU countries want to support new investments in wind, solar, geothermal, hydropower and nuclear electricity, for example - a point over which France and Germany have wrestled - they should use a two-way contract for difference (CfD) or an equivalent contract, the draft said.
The aim is to provide a stable revenue stream to investors, and help make consumers' energy bills less volatile, even though rolling back electricity prices is tougher than it appears. Restricting this support to renewable and low-carbon electricity also aims to speed up Europe's shift away from fossil fuels.
Two-way CfDs offer generators a fixed "strike price" for their electricity, regardless of the price in short-term energy markets. If the market price is above the CfD strike price, then the extra revenue the generator receives should be handed out to final electricity consumers, the draft EU document said.
Countries should also make it easier for power buyers to sign power purchase agreements (PPA) - another type of long-term contract to directly buy electricity from a generator.
Governments should also make sure consumers have access to fixed-price electricity contracts - echoing France's new electricity pricing scheme to reassure Brussels - giving them the option to avoid a contract that would expose them to volatile prices swings in energy markets, the draft said.
If European energy prices were to spike to extreme levels again, the Commission suggested allowing national governments to temporarily intervene to fix prices while weighing emergency measures to limit prices where needed, and offer consumers and small businesses a share of their electricity at a lower price.
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Hydro once made up around half of Alberta's power capacity. Why does Alberta have so little now?
Alberta Hydropower Potential highlights renewable energy, dams, reservoirs, grid flexibility, contrasting wind and solar growth with limited investment, regulatory hurdles, river basin resources, and decarbonization pathways across Athabasca, Peace, and Slave River systems.
Key Points
It is the technical capacity for new hydro in Alberta's river basins to support a more reliable, lower carbon grid.
✅ 42,000 GWh per year developable hydro identified in studies.
✅ Major potential in Athabasca, Peace, and Slave River basins.
✅ Barriers include high capital costs, market design, water rights.
When you think about renewable energy sources on the Prairies, your mind may go to the wind farms in southern Alberta, or even the Travers Solar Project, southeast of Calgary.
Most of the conversation around renewable energy in the province is dominated by advancements in solar and wind power, amid Alberta's renewable energy surge that continues to attract attention.
But what about Canada's main source of electricity — hydro power?
More than half of Canada's electricity is generated from hydro sources, with 632.2 terawatt-hours produced as of 2019. That makes it the fourth largest installed capacity of hydropower in the world.
But in Alberta, it's a different story.
Currently, hydro power contributes between three and five per cent of Alberta's energy mix, while fossil fuels make up about 89 per cent.
According to Canada's Energy Future report from the Canada Energy Regulator, by 2050 it will make up two per cent of the province's electricity generation shares.
So why is it that a province so rich in mountains and rivers has so little hydro power?
Hydro's history in Alberta
Hydro power didn't always make up such a small sliver of Alberta's electricity generation. Hydro installations began in the early 20th century as the province's population exploded.
Grant Berg looks after engineering for hydro for TransAlta, Alberta's largest producer of hydro power with 17 facilities across the province.
"Our first plant was Horseshoe, which started in 1911 that we formed as Calgary Power," he said.
"It was really in response to the City of Calgary growing and having some power needs."
Berg said in 1913, TransAlta's second installation, the Kananaskis Plant, started as Calgary continued to grow.
A historical photo of a hydro-electric dam in Kananaskis Alta. taken in 1914.
Hydro power plant in Kananaskis as seen in 1914. (Glenbow Archives)
Some bigger installations were built in the 1920s, including Ghost reservoir, but by mid-century population growth increased.
"Quite a large build out really, I think in response to the growth in Alberta following the war. So through the 1950s really quite a large build out of hydro from there."
By the 1950s, around half of the province's installed capacity was hydro power.
"Definitely Calgary power was all hydro until the 1950s," said Berg.
Hydro potential in the province
Despite the current low numbers in hydroelectricity, Alberta does have potential.
According to a 2010 study, there is approximately 42,000 gigawatt-hours per year of remaining developable hydroelectric energy potential at identified sites.
An average home in Alberta uses around 7,200 kilowatt-hours of electricity per year, meaning that the hydro potential could power 5.8 million homes each year.
"This volume of energy could be sufficient to serve a significant amount of Alberta's load and therefore play a meaningful role in the decarbonization of the province's electric system," the Alberta Electric System Operator said in its 2022 Pathways to Net-Zero Emissions report.
Much of that potential lies in northern Alberta, in the Athabasca, Peace and Slave River basins.
The AESO report says that despite the large resource potential, Alberta's energy-only market framework has attracted limited investment in hydroelectric generation.
Hydro power was once a big deal in Alberta, but investment in the industry has been in decline since the 1950s. Climate change reporter Christy Climenhaga explains why.
So why does Alberta leave out such a large resource potential on the path to net zero?
The government of Alberta responded to that question in a statement.
"Hydro facilities, particularly large scale ones involving dams, are associated with high costs and logistical demands," said the Ministry of Affordability and Utilities.
"Downstream water rights for other uses, such as irrigation, further complicate the development of hydro projects."
The ministry went on to say that wind and solar projects have increased far more rapidly because they can be developed at relatively lower cost and shorter timelines, and with fewer logistical demands.
"Sources from wind power and solar are increasingly more competitive," said Jean-Denis Charlebois, chief economist with the Canadian Energy Regulator.
Hydro on the path to net zero
Hydro power is incredibly important to Canada's grid, and will remain so, despite growth in wind and solar power across the province.
Charlebois said that across Canada, the energy make-up will depend on the province.
"Canadian provinces will generate electricity in very different ways from coast to coast. The major drivers are essentially geography," he said.
Charlebois says that in British Columbia, Manitoba, Quebec and Newfoundland and Labrador, hydropower generation will continue to make up the majority of the grid.
"In Alberta and Saskatchewan, we see a fair bit of potential for wind and solar expansion in the region, which is not necessarily the case on Canada's coastlines," he said.
And although hydro is renewable, it does bring its adverse effects to the environment — land use changes, changes in flow patterns, fish populations and ecosystems, which will have to be continually monitored.
"You want to be able to manage downstream effects; make sure that you're doing all the proper things for the environment," said Ryan Braden, director of mining and hydro at TransAlta.
Braden said hydro power still has a part to play in Alberta, even with its smaller contributions to the future grid.
"It's one of those things that, you know, the wind doesn't blow or the sun doesn't shine, this is here. The way we manage it, we can really support that supply and demand," he said.
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YVR welcomes government funding for new Electric Vehicle Chargers
YVR EV Charging Infrastructure Funding backs new charging stations at Vancouver International Airport via ZEVIP and CleanBC Go Electric, supporting Net Zero 2030 with Level 2 and DC fast charging across Sea Island.
Key Points
A federal and provincial effort to expand EV charging at YVR, accelerating airport electrification toward Net Zero 2030.
✅ Up to 74 new EV charging outlets across Sea Island by 2025
✅ Funded through ZEVIP and CleanBC Go Electric programs
✅ Supports passengers, partners, and YVR fleet electrification
Vancouver International Airport (YVR) welcomes today’s announcement from the Government of Canada, which confirms new federal funding under Natural Resource Canada’s Zero Emission Vehicle Infrastructure Program (ZEVIP) and broader zero-emission vehicle incentives for essential infrastructure at the airport that will further enable YVR to achieve its climate targets.
This federal funding, combined with funding through the Government of British Columbia’s CleanBC Go Electric program, which includes EV charger rebates, will support the installation of up to 74 additional Electric Vehicle (EV) Charging outlets across Sea Island over the next three years. EV charging infrastructure is identified as a key priority in the airport’s Roadmap to Net Zero 2030. It is also an important part of its purpose in being a Gateway to the New Economy.
“We know that our passengers’ needs and expectations are changing as EV adaptation increases across our region and policies like the City’s EV-ready requirements take hold, we are always working hard to anticipate and exceed these expectations and provide world-class amenities at our airport,” said Tamara Vrooman, President & CEO, Vancouver Airport Authority.
This airport initiative is among 26 projects receiving $19 million under ZEVIP, which assists organizations as they adapt to the Government of Canada’s mandatory target for all new light-duty cars and passenger trucks to be zero-emission by 2035, and to provincial momentum such as B.C.'s EV charging expansion across the network.
“We are grateful to have found partners at all levels of government as we take bold action to become the world’s greenest airport. Not only will this critical funding support us as we work to the complete electrification of our airport operations, and as regional innovations like Harbour Air’s electric aircraft demonstrate what’s possible, but it will help us in our role supporting the mutual needs of our business partners related to climate action,” Vrooman continued.
These new EV Charging stations are planned to be installed by 2025, and will provide electricity to the YVR fleet, commercial and business partners’ vehicles, as well as passengers and the public, complementing BC Hydro’s expanding charging network in southern B.C. Currently, YVR provides 12 free electric vehicle charging stalls (Level Two) at its parking facilities, as well as one DC fast-charging stall.
This exciting announcement comes on the heels of the Province of BC’s Integrated Marketplace Initiative (IMI) pilot program in November 2022, a partnership between YVR and the Province of British Columbia to invest up to 11.5 million to develop made-in-BC clean-tech solutions for use at the airport, and related programs offering home and workplace charging rebates are accelerating adoption.
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Ontario explores possibility of new, large scale nuclear plants
Ontario Nuclear Expansion aims to meet rising electricity demand and decarbonization goals, complementing renewables with energy storage, hydroelectric, and SMRs, while reducing natural gas reliance and safeguarding grid reliability across the province.
Key Points
A plan to add large nuclear capacity to meet demand, support renewables, cut gas reliance, and maintain grid reliability
✅ Adds firm, low-carbon baseload to complement renewables
✅ Reduces reliance on natural gas during peak and outages
✅ Requires public and Indigenous engagement on siting
Ontario is exploring the possibility of building new, large-scale nuclear plants in order to meet increasing demand for electricity and phase out natural gas generation.
A report late last year by the Independent Electricity System Operator found that the province could fully eliminate natural gas from the electricity system by 2050, starting with a moratorium in 2027, but it will require about $400 billion in capital spending and more generation including new, large-scale nuclear plants.
Decarbonizing the grid, in addition to new nuclear, will require more conservation efforts, more renewable energy sources and more wind and solar power sources and more energy storage, the report concluded.
The IESO said work should start now to assess the reliability of new and relatively untested technologies and fuels to replace natural gas, and to set up large, new generation sources such as nuclear plants and hydroelectric facilities.
The province has not committed to a natural gas moratorium or phase-out, or to building new nuclear facilities other than its small modular reactor plans, but it is now consulting on the prospect.
A document recently posted to the government’s environmental registry asks for input on how best to engage the public and Indigenous communities on the planning and location of new generation and storage facilities.
Building new nuclear plants is “one pathway” toward a fully electrified system, Energy Minister Todd Smith said in an interview.
“It’s a possibility, for sure, and that’s why we’re looking for the feedback from Ontarians,” he said. “We’re considering all of the next steps.”
Environmental groups such as Environmental Defence oppose new nuclear builds, as well as the continued reliance on natural gas.
“The IESO’s report is peddling the continued use of natural gas under the guise of a decarbonization plan, and it takes as a given the ramping up of gas generation and continues to rely on gas generated electricity until 2050, which is embarrassingly late,” said Lana Goldberg, Environmental Defence’s Ontario climate program manager.
“Building new nuclear is absurd when we have safe and much cheaper alternatives such as wind and solar power.”
The IESO has said the flexibility natural gas provides, alongside new gas plants, is needed to keep the system stable while new and relatively untested technologies are explored and new infrastructure gets built, but also as an electricity supply crunch looms.
Ontario is facing a shortfall of electricity with the Pickering nuclear station set to be retired, others being refurbished, and increasing demands including from electric vehicles, new electric vehicle and battery manufacturing, electric arc furnaces for steelmaking, and growth in the greenhouse and mining industries.
The government consultation also asks whether “additional investment” should be made in clean energy in the short term in order to decrease reliance on natural gas, “even if this will increase costs to the electricity system and ratepayers.”
But Smith indicated the government isn’t keen on higher costs.
“We’re not going to sacrifice reliability and affordability,” he said. “We have to have a reliable and affordable system, otherwise we won’t have people moving to electrification.”
The former Liberal government faced widespread anger over high hydro bills _ highlighted often by the Progressive Conservatives, then in Opposition — driven up in part by long-term contracts at above-market rates with clean power producers secured to spur a green energy transition.
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Why Fort Frances wants to build an integrated microgrid to deliver its electricity
Fort Frances Microgrid aims to boost reliability in Ontario with grid-connected and island modes, Siemens feasibility study, renewable energy integration, EV charging expansion, and resilience modeled after First Nations projects and regional biomass initiatives.
Key Points
A community microgrid in Fort Frances enabling grid and island modes to improve reliability and integrate renewables.
✅ Siemens-led feasibility via FedNor funding
✅ Grid-connected or islanded for outage resilience
✅ Integrates renewables, EV charging, and industry growth
When the power goes out in Fort Frances, Ont., the community may be left in the dark for hours.
The hydro system's unreliability — caused by its location on the provincial power grid — has prompted the town to seek a creative solution: its own self-contained electricity grid with its own source of power, known as a microgrid.
Located more than 340 kilometres west of Thunder Bay, Ont., on the border of Minnesota, near the Great Northern Transmission Line corridor, Fort Frances gets its power from a single supply point on Ontario's grid.
"Sometimes, it's inevitable that we have to have like a six- to eight-hour power outage while equipment is being worked on, and that is no longer acceptable to many of our customers," said Joerg Ruppenstein, president and chief executive officer of Fort Frances Power Corporation.
While Ontario's electrical grid serves the entire province, and national efforts explore macrogrids, a microgrid is contained within a community. Fort Frances hopes to develop an integrated, community-based electric microgrid system that can operate in two modes:
- Grid-connected mode, which means it's connected to the provincial grid and informed by western grid planning approaches
- Island mode, which means it's disconnected from the provincial grid and operates independently
The ability to switch between modes allows flexibility. If a storm knocks down a line, the community will still have power.
The town has been given grant funding from the Federal Economic Development Agency for Northern Ontario (FedNor), echoing smart grid funding in Sault Ste. Marie initiatives, for the project. On Monday night, council voted to grant a request for proposal to Siemens Canada Limited to conduct a feasibility study into a microgrid system.
The study, anticipated to be completed by the end of 2023 or early 2024, will assess what an integrated community-based microgrid system could look like in the town of just over 7,000 people, said Faisal Anwar, chief administrative officer of Fort Frances. A timeline for construction will be determined after that.
The community is still reeling from the closure of the Resolute Forest Products pulp and paper mill in 2014 and faces a declining population, said Ruppenstein. It's hoped the microgrid system will help attract new industry to replace those lost workers and jobs, drawing on Manitoba's hydro experience as a model.
This gives the town a competitive advantage.
"If we were conceivably to attract a larger industrial player that would consume a considerable amount of energy, it would result in reduced rates for everyone…we're the only utility really in Ontario that can offer that model," Ruppenstein said.
The project can also incorporate renewable energy like solar or wind power, as seen in B.C.'s clean energy shift efforts, into the microgrid system, and support the growth of electric vehicles, he said. Many residents fill their gas tanks in Minnesota because it's cheaper, but Fort Frances has the potential to become a hub for electric vehicle charging.
A few remote First Nations have recently switched to microgrid systems fuelled by green energy, including Gull Bay First Nation and Fort Severn First Nation. These are communities that have historically relied on diesel fuel either flown in, which is incredibly expensive, or transported via ice roads, which are seeing shorter seasons each year.
Natural Resources Minister Jonathan Wilkinson was in Thunder Bay, Ont., to announce $35 million for a biomass generation facility in Whitesand First Nation, complementing federal funding for the Manitoba-Saskatchewan transmission line elsewhere in the region.
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Canada's largest electricity battery storage project coming to southwestern Ontario
Oneida Energy Storage Project, a 250 MW lithium-ion battery in Haldimand County, enhances Ontario's clean energy capacity, grid reliability, and peak demand management, developed with Six Nations partners and private-public collaboration.
Key Points
A 250 MW lithium-ion battery in Ontario storing power to stabilize the grid and deliver clean electricity.
✅ 250 MW lithium-ion grid-scale battery in Haldimand County
✅ Developed with Six Nations, Northland Power, NRStor, Aecon
✅ Enhances grid reliability, peak shaving, emissions reduction
The Ontario government announced it is working to build Canada's largest electricity battery storage project in Haldimand County, part of Ontario's push into energy storage amid a looming supply crunch. Ontario Premier Doug Ford and Deputy Prime Minister Chrystia Freeland made the announcement in Ohsweken, Ont.
The 250-megawatt Oneida Energy storage project is being developed in partnership with the Six Nations of the Grand River Development Corporation, Northland Power, NRStor and Aecon Group.
The Ontario government announced on Friday it is working to build Canada's largest electricity battery storage project in Haldimand County.
On Friday, Ontario Premier Doug Ford and Deputy Prime Minister Chrystia Freeland made the announcement in Ohsweken, Ont.
The 250-megawatt Oneida Energy storage project is being developed in partnership with the Six Nations of the Grand River Development Corporation, Northland Power, NRStor and Aecon Group.
“It will more than double the province's energy storage resources and provide enough electricity to power a city approximately the size of Oshawa,” said Ford, noting Ontario's growing battery storage expansion across the grid.
“We need to continue to find ways to keep our energy clean and green,” said Ford, including initiatives like the Hydrogen Innovation Fund to spur innovation.
The federal government said they are providing a further $50 million in funding, coinciding with national investments such as the B.C. battery plant to scale capacity.
The premier said the project will begin operating in 2025 and will more than double the amount of clean energy storage.
Officials with the Six Nations said they have invested in the project that will provide economic returns and 97 per cent of the construction workforce to build it.
"This project is an example of what is possible when private and public companies, multiple levels of government, and their agencies work alongside a progressive Indigenous partner in pursuit of innovative solutions,” said Matt Jamieson, President and CEO of Six nations of the Grand River Development Corporation. “As with all our development efforts, we have studied the project to ensure it aligns with our community values, we are confident the outcome will create ratepayer savings, and move us closer to a Net Zero future for our coming generations."
According to the province, it has directed the independent electricity system operator to enter into a 20-year contract for this project with a goal to grow the province's clean energy supply, alongside transmission efforts like the Lake Erie Connector to enhance reliability.
The province said the Oneida Energy storage project is expected to reduce emissions by between 2.2 to 4.1 million tonnes, the equivalent to taking up to 40,000 cars off the road.
The project will use large scale lithium batteries, with regional supply bolstered by the Niagara battery plant, to store surplus energy from the power grid then feed it back into the system when it’s needed.
“Power that is generated and it can’t be utilized, this system will help harness that, store it for a period of time, and it will maximize value for the rate payer,” said Jamieson.
Jamieson said he is proud that the Six Nations is a founding developer in the project.
The facility will not actually be in Six Nations. It will be near the community of Jarvis in Haldimand County.
For Six Nationals elected Chief Mark Hill, it’s a major win as Ontario's EV sector grows with the Oakville EV deal and related projects.
“We want to continue to be a driver. We want to show Canada that we can also be a part of green solution,” Hill said.
But Hill admitted the Six Nations Community remains deeply divided over a number of longstanding issues.
“We still have a lot of internal affairs within our own community that we have to deal with. I think it’s really time once and for all to come together and figure this out,” said Hill.
The traditional leadership said they were left out of the decision making.
“No voice of ours was even heard today in that building,” said Deyohowe:to, the chief of the Cayuga Snipe Clan.
According to the Cayuga Snipe Clan, consultation with the Haudenasauene council is required for this type of development but they said it didn't happen.
“We’ve never heard of this before. No one came to the community and said this was going to happen and for the community we are not going to let that happen,” said Deyohowe:to.
The Six Nations Development Corporation said it did reach out to the Haudenosaunee chiefs and sent multiple letters in 2021 inviting them to participate.
