Quebec to retrofit Gentilly-2 plant

ESCC COVID-19 Response coordinates utilities, public power, and cooperatives to protect the energy grid and electricity reliability, aligning with DOE, DHS, CDC, FERC, and NERC on continuity of operations, mutual assistance, and supply chain resilience.

Key Points

An industry government effort ensuring reliability, operations continuity and supply chain stability during COVID-19.

✅ Twice weekly ESCC calls align DOE, DHS, HHS, CDC, FERC, NERC priorities.

✅ Focus on control centers, generation, quarantine access, mutual aid.

✅ Resource Guide supports localized decisions and supply chain resilience.

The nation’s investor-owned electric companies, public power utilities, and electric cooperatives are working together to protect the energy grid as the U.S. grid addresses COVID-19 challenges and ensure continued access to safe and reliable electricity during the COVID-19 global health crisis.

The electric power industry has been planning for years, including extensive disaster planning across utilities, for an emergency like the COVID-19 pandemic, as well as countless other types of emergencies, and the industry is coordinating closely with government partners through the Electricity Subsector Coordinating Council (ESCC) to ensure that organizations have the resources they need to keep the lights on.

The ESCC is holding high-level coordination calls twice a week with senior leadership from the Departments of Energy, Homeland Security, and Health and Human Services, the Centers for Disease Control and Prevention, the Federal Energy Regulatory Commission, and the North American Electric Reliability Corporation. These calls help ensure that industry and government work together to resolve any challenges that arise during this health emergency and that electricity remains safe for customers.

“Electricity and the energy grid are indispensable to our society, and one of our greatest strengths as an industry is our ability to convene and adapt quickly to changing circumstances and challenging events,” said Edison Electric Institute President Tom Kuhn. “Our industry plans for all types of contingencies, with examples such as local response planning, and strong industry-government coordination and cross-sector collaboration are critical to our planning and response. We appreciate the ongoing leadership and support of our government partners as we all respond to COVID-19 and power through this crisis together.”

The ESCC quickly mobilized and established strategic working groups dedicated to identifying and solving for short-, medium-, and long-term issues facing the industry during the COVID-19 pandemic, with utilities implementing necessary precautions to maintain service across regions.

The five current areas of focus are:

1. Continuity of operations at control centers, including on-site staff lockdowns when needed
2. Continuity of operations at generation facilities
3. Access to, and operations in, restricted or quarantined areas
4. Protocols for mutual assistance
5. Supply chain challenges

“The electric power industry has taken steps to prepare for the evolving coronavirus challenges, while maintaining our commitment to the communities we serve, including customer relief efforts announced by some providers,” said National Rural Electric Cooperative Association CEO Jim Matheson. “We have a strong track record of preparing for many kinds of emergencies that could impact the ability to generate and deliver electricity. While planning for this situation is unique from other business continuity planning, we are taking actions to prepare to operate with a smaller workforce, potential disruptions in the supply chain, and limited support services for an extended period of time.”

The ESCC has developed a COVID-19 Resource Guide linked here and available at electricitysubsector.org. This document was designed to support electric power industry leaders in making informed localized decisions in response to this evolving health crisis. The guide will evolve as additional recommended practices are identified and as more is learned about appropriate mitigation strategies.

“The American Public Power Association (APPA) continues to work with our communityowned public power members and our industry and government partners to gather and share upto-date information, best practices, and guidance to support them in safely maintaining operational integrity,” said APPA CEO Joy Ditto.

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TransAlta Renewables US wind farms achieved commercial operation, adding 119 MW of wind energy capacity in Pennsylvania and New Hampshire, backed by PPAs with Microsoft, Partners Healthcare, and NHEC, and supported by tax equity financing.

Key Points

Two US wind projects totaling 119 MW, now online under PPAs and supported by tax equity financing.

✅ 119 MW online in Pennsylvania and New Hampshire

✅ PPAs with Microsoft, Partners Healthcare, and NHEC

✅ About USD 126 million raised via tax equity

TransAlta Renewables Inc says two US wind farms, with a total capacity of 119 MW and operated by its parent TransAlta Corp, became operational in December, amid broader build-outs such as Enel's 450-MW U.S. project coming online and, in Canada, Acciona's 280-MW Alberta wind farm advancing as well.

The 90-MW Big Level wind park in Pennsylvania started commercial operation on December 19. It sells power to technology giant Microsoft Corporation under a 15-year contract, reflecting big-tech procurement alongside Amazon's clean energy projects in multiple markets.

The 29-MW Antrim wind facility in New Hampshire is operational since December 24. It is selling power under 20-year contracts with Boston-based non-profit hospital and physicians network Partners Healthcare and New Hampshire Electric Co-op, mirroring East Coast activity at Amazon Wind Farm US East now fully operational.

The Canadian renewable power producer, which has economic interest in the two wind parks, said that upon their reaching commercial operations, it raised about USD 126 million (EUR 113m) of tax equity to partially fund the projects, as mega-deployments like Invenergy and GE's record North American project and capital plans such as a $200 million Alberta build by a Buffett-linked company underscore financing momentum.

"We continue to pursue additional growth opportunities, including potential drop-down transactions with TransAlta Corp," TransAlta Renewables president John Kousinioris commented.

The comment comes as TransAlta scrapped an Alberta wind project amid Alberta policy shifts.

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bGen Thermal Energy Storage stores high-temperature heat in crushed rocks, enabling on-demand steam, hot water, or hot air; integrates renewables, shifts load with off-peak electricity, and decarbonizes campus heating at SUNY Purchase with NYPA.

Key Points

A rock-based TES system storing heat to deliver steam, hot water, or hot air using renewables or off-peak power.

✅ Uses crushed rocks to store high-temperature heat

✅ Cuts about 550 metric tons CO2 annually at SUNY Purchase

✅ Integrates renewables and off-peak electricity with NYPA

Brenmiller Energy Ltd. (NASDAQ: BNRG), in collaboration with the New York Power Authority (NYPA), a utility pursuing grid software modernization to improve reliability, has successfully deployed its first bGen™ thermal energy storage (TES) system in the United States at the State University of New York (SUNY) Purchase College. This milestone project, valued at $2.5 million, underscores the growing role of TES in advancing sustainable energy solutions.

Innovative TES Technology

The bGen™ system utilizes crushed rocks to store high-temperature heat, which can be harnessed to generate steam, hot air, or hot water on demand. This approach allows for the efficient use of excess renewable energy or off-peak electricity, and parallels microreactor storage advances that broaden thermal options, providing a reliable and cost-effective means of meeting heating needs. At SUNY Purchase College, the bGen™ system is designed to supply nearly 100% of the heating requirements for the Physical Education Building.

Environmental Impact

The implementation of the bGen™ system is expected to eliminate approximately 550 metric tons of greenhouse gas emissions annually. This reduction aligns with New York State's ambitious climate goals, including a 40% reduction in greenhouse gas emissions by 2030, even as transmission constraints can limit cross-border imports. The project also demonstrates the potential of TES to support the state's transition to a cleaner and more resilient energy system.

Collaborative Effort

The successful deployment of the bGen™ system at SUNY Purchase College is the result of a collaborative effort between Brenmiller Energy and NYPA. The project was partially funded by a grant from the Israel-U.S. Binational Industrial Research and Development (BIRD) Foundation. This partnership highlights the importance of international cooperation in advancing innovative energy technologies, as seen in OPG-TVA nuclear collaboration efforts across North America.

Future Prospects

The successful installation and operation of the bGen™ system at SUNY Purchase College serve as a model for broader adoption of TES technology in institutional settings, as OPG's SMR commitment signals parallel low-carbon investment across the region. Brenmiller Energy and NYPA plan to share the project's findings through a webinar hosted by the Renewable Thermal Collaborative on May 19, 2025. This initiative aims to promote the scalability and replicability of TES solutions across New York State and beyond.

As the demand for sustainable energy solutions continues to grow, the successful deployment of the bGen™ system at SUNY Purchase College marks a significant step forward in the integration of TES technology into the U.S. energy landscape, while projects like Pickering B refurbishment underscore parallel clean power investments. The project not only demonstrates the feasibility of TES but also sets a precedent for future initiatives aimed at reducing carbon emissions and enhancing energy efficiency.

Brenmiller Energy's commitment to innovation and sustainability positions the company as a key player in the evolving energy sector. With continued support from partners like NYPA and the BIRD Foundation, and as jurisdictions advance first SMR deployments in North America, Brenmiller Energy is poised to expand the reach of its TES solutions, contributing to a more sustainable and resilient energy future.

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Canada Wind Energy Costs are plunging as renewable energy auctions, CfD contracts, and efficient turbines drive prices to 2-4 cents/kWh across Alberta and Saskatchewan, outcompeting grid power via competitive bidding and improved capacity factors.

Key Points

Averaging 2-4 cents/kWh via auctions, CfD support, and bigger turbines, wind is now cost-competitive across Canada.

✅ Alberta CfD bids as low as 3.9 cents/kWh.

✅ Turbine outputs rose from 1 MW to 3.3 MW per tower.

✅ Competitive auctions cut costs ~70% over nine years.

It's taken a decade of technological improvement and a new competitive bidding process for electrical generation contracts, but wind may have finally come into its own as one of the cheapest ways to create power.

Ten years ago, Ontario was developing new wind power projects at a cost of 28 cents per kilowatt hour (kWh), the kind of above-market rate that the U.K., Portugal and other countries were offering to try to kick-start development of renewables. 

Now some wind companies say they've brought generation costs down to between 2 and 4 cents — something that appeals to provinces that are looking to significantly increase their renewable energy deployment plans.

The cost of electricity varies across Canada, by province and time of day, from an average of 6.5 cents per kWh in Quebec to as much as 15 cents in Halifax.

Capital Power, an Edmonton-based company, recently won a contract for the Whitla 298.8-megawatt (MW) wind project near Medicine Hat, Alta., with a bid of 3.9 cents per kWh, at a time when three new solar facilities in Alberta have been contracted at lower cost than natural gas, underscoring the trend. That price covers capital costs, transmission and connection to the grid, as well as the cost of building the project.

Jerry Bellikka, director of government relations, said Capital Power has been building wind projects for a decade, in the U.S., Alberta, B.C. and other provinces. In that time the price of wind generation equipment has been declining continually, while the efficiency of wind turbines increases.

Increased efficiency

"It used to be one tower was 1 MW; now each turbine generates 3.3 MW. There's more electricity generated per tower than several years ago," he said.

One wild card for Whitla may be steel prices — because of the U.S. and Canada slapping tariffs on one other's steel and aluminum products. Whitla's towers are set to come from Colorado, and many of the smaller components from China.

Canada introduces new surtaxes to curb flood of steel imports

"We haven't yet taken delivery of the steel. It remains to be seen if we are affected by the tariffs." Belikka said.

Another company had owned the site and had several years of meteorological data, including wind speeds at various heights on the site, which is in a part of southern Alberta known for its strong winds.

But the choice of site was also dependent on the municipality, with rural Forty Mile County eager for the development, Belikka said.

Alberta aims for 30% electricity from wind by 2030

Alberta wants 30 per cent of its electricity to come from renewable sources by 2030 and, as an energy powerhouse, is encouraging that with a guaranteed pricing mechanism in what is otherwise a market-bidding process.

While the cost of generating energy for the Alberta Electric System Operator (AESO) fluctuates hourly and can be a lot higher when there is high demand, the winners of the renewable energy contracts are guaranteed their fixed-bid price.

The average pool price of electricity last year in Alberta was 5 cents per kWh; in boom times it rose to closer to 8 cents. But if the price rises that high after the wind farm is operating, the renewable generator won't get it, instead rebating anything over 3.9 cents back to the government.

On the other hand, if the average or pool price is a low 2 cents kWh, the province will top up their return to 3.9 cents.

This contract-for-differences (CfD) payment mechanism has been tested in renewable contracts in the U.K. and other jurisdictions, including some U.S. states, according to AESO.

Competitive bidding in Saskatchewan

In Saskatchewan, the plan is to double its capacity of renewable electricity, to 50 per cent of generation capacity, by 2030, and it uses an open bidding system between the private sector generator and publicly owned SaskPower.

In bidding last year on a renewable contract, 15 renewable power developers submitted bids, with an average price of 4.2 cents per kWh.

One low bidder was Potentia with a proposal for a 200 MW project, which should provide electricity for 90,000 homes in the province, at less than 3 cents kWh, according to Robert Hornung of the Canadian Wind Energy Association.

"The cost of wind energy has fallen 70 per cent in the last nine years," he says. "In the last decade, more wind energy has been built than any other form of electricity."

Ontario remains the leading user of wind with 4,902 MW of wind generation as of December 2017, most of that capacity built under a system that offered an above-market price for renewable power, put in place by the previous Liberal government.

In June of last year, the new Conservative government of Doug Ford halted more than 700 renewable-energy projects, one of them a wind farm that is sitting half-built, even as plans to reintroduce renewable projects continue to advance.

The feed-in tariff system that offered a higher rate to early builders of renewable generation ended in 2016, but early contracts with guaranteed prices could last up to 20 years.

Hornung says Ontario now has an excess of generating capacity, as it went on building when the 2008-9 bust cut market consumption dramatically.

But he insists wind can compete in the open market, offering low prices for generation when Ontario needs new  capacity.

"I expect there will be competitive processes put in place. I'm quite confident wind projects will continue to go ahead. We're well positioned to do that."

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Jersey Electricity Standby Charge proposes a grid-backup fee for commercial self-generators of renewable energy, with a review delaying implementation; potential tariff impacts include 10-15 percent price rises, cost recovery, and network reliability.

Key Points

A grid-backup fee for Jersey self-generating businesses to share network costs fairly and curb electricity price rises.

✅ Applies to commercial self-generation using renewables or not

✅ Excludes full exporters and pre-charge installations

✅ Aims to recover grid costs and avoid 10-15% price rises

Electricity prices could rise by ten to 15 per cent if a standby charge for some commercial customers is not implemented, the chief executive of Jersey Electricity has warned.

Jersey Electricity has proposed extending a monthly fee to commercial customers who generate their own power through renewable means but still wish to be connected to Jersey’s grid as a back-up, echoing Ontario energy storage efforts to shore up reliability.

The States recently unanimously backed a proposal lodged by Deputy Carolyn Labey to delay administering the levy until a review could be carried out, as seen in the UK grid's net-zero transformation debates influencing policy. The charge, was due to be implemented next month but will now not be introduced until May, or later if the review has not concluded.

But Chris Ambler, JE chief executive, warned that failing to implement the standby charge could lead to additional costs for customers.

Some of JE’s commercial customers have already been charged a standby fee after generating their own power through non-renewable means.

The charge does not apply to businesses which export all of their electricity back into the system as part of a buy-back scheme or those which install self-generation facilities before the charge is implemented.

Deputy Labey argued that the Island had done ‘absolutely nothing’ to support the use of renewable energies and instead were discouraging locally generated power by allowing JE to set a standby charge.

She added that she was pleased that the Council of Ministers had already starting reviewing the charges but the debate needed to go ahead to ensure the work continued after the May election.

During a States debate last month, she said: ‘It is increasingly concerning that we, as an island in the 21st century, are happy for our electricity to be provided to us by an unregulated, publicly listed for-profit company with a monopoly on energy.

‘I also think that introducing a charge on renewables at a time when the world is experiencing a revolution in renewable energies, including offshore vessel charging solutions, which are becoming increasingly economic, is something that needs to be investigated.

‘Jersey should be looking to diversify our electricity production and supply, to help protect us from price and currency fluctuations and to ensure that we, as an island, receive the best deal possible for Islanders.’

Mr Ambler said that any price increase would be dependent on the future take-up and use of renewable-energy technology in Jersey.

He said: ‘The cost impact would not be significant in the short term but in the long term it could be significant. I think that we are obliged to let our customers know that.

‘It is very difficult to assess but if we are not able to levy a fair charge, then, as electricity shortages in Canada have shown, we could see prices rise by ten to 15 per cent over time.’

Mr Ambler added that his company was in favour of the use of renewable energy, with a third of the company’s electricity being generated by hydroelectric sources, but that the costs of implementing it needed to be fairly distributed, given how big battery rule changes can affect project viability elsewhere in the market.

And he said that, while it was difficult to quantify how much could be lost if the standby charge was not implemented, it could cost the company over £10 million.

‘In 2014, we only increased our prices by one per cent,’ he said. ‘We are reviewing our prices at the moment but if we did put an increase in place it would be modest and it would not be linked to the standby charge.’

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Duke Energy Smart Meters enable remote meter reading, daily energy usage data, and two-way outage detection via AMI, with encrypted data, faster restoration, and remote connect/disconnect for Indiana customers in Howard County.

Key Points

Advanced meters that support remote readings, daily usage insights, two-way outage detection, and secure, encrypted data.

✅ Daily energy usage available online the next day

✅ Two-way communications speed outage detection and restoration

✅ Remote connect/disconnect; manual reads optional with opt-out fee

Say goodbye to your neighborhood meter reader. Say hello to your new smart meter.

Over the next three months, Duke Energy will install nearly 43,000 new high-tech electric meters for Howard County customers that will allow the utility company to remotely access meters via the digital grid instead of sending out employees to a homeowner's property for walk-by readings.

That means there's no need to estimate bills when meters can't be easily accessed, such as during severe weather or winter storms.

Other counties serviced by Duke Energy slated to receive the meters include Miami, Tipton, Cass and Carroll counties.

Angeline Protogere, Duke Energy's lead communication consultant, said besides saving the company money and manpower, the new smart meters come with a host of benefits for customers enabled by smart grid solutions today.

The meters are capable of capturing daily energy usage data, which is available online the next day. Having this information available on a daily basis can help customers make smarter energy decisions and support customer analytics that avoid billing surprises at the end of the month, she said.

"The real advantage is for the consumer, because they can track their energy usage and adjust their usage before the bills come," Protogere said.

When it comes to power outages, the meters are capable of two-way communications. That allows the company to know more about an outage through synchrophasor monitoring, which can help speed up restoration. However, customers will still need to notify Duke Energy if their power goes out.

If a customer is moving, they don't have to wait for a Duke Energy representative to come to the premises to connect or disconnect the energy service because requests can be performed remotely.

Protogere said when it comes to installing the meters, the changeover takes less than 5 minutes to complete. Customers should receive advance notices from the company, but the technician also will knock on the door to let the customer know they are there.

If no one is available and the meter is safely accessible, the technician will go ahead and change out the meter, Protogere said. There will be a momentary outage between the time the old meter is removed and the new meter is installed.

Kokomo and the surrounding areas are one of the last parts of the state to receive Duke Energy's new, high-tech meters, which are commonly used by other utility companies and in smart city initiatives across the U.S.

Protogere said statewide, the company started installing smart meters in August 2016 as utilities deploy digital transformer stations to modernize the grid. To date, they have installed 694,000 of the 854,000 they have planned for the state.

The company says the information stored and transmitted on the smart meters is safe, protected and confidential. Duke Energy said on its website that it does not share data with anyone without customers' authorization. The information coming from the meters is encrypted and protected from the moment it is collected until the moment it is purged, the company said.

Digital smart meter technology uses radio frequency bands that have been used for many years in devices such as baby monitors and medical monitors. The radio signals are far below the levels emitted by common household appliances and electronics, including cellphones and microwave ovens.

According to the World Health Organization, FCC, U.S. Food and Drug Administration and Electric Power Research Institute, no adverse health effects have been shown to occur from the radio frequency signals produced by smart meters or other such wireless networks.

However, customers can still opt-out of getting a smart meter and continue to have their meter manually read.

Those who choose not to get a smart meter must pay a $75 initial opt-out fee and an additional $17.50 monthly meter reading charge per account.

If smart meters have not yet been installed, Duke Energy will waive the $75 initial opt-out fee if customers notify the company they want to opt out within 21 days of receiving the installation postcard notice.

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