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ESCC COVID-19 Resource Guide outlines control center continuity, sequestration, social distancing, remote operations, testing priorities, mutual assistance, supply chain risk, and PPE protocols to sustain grid reliability and plant operations during the COVID-19 pandemic.

Key Points

An industry guide to COVID-19 mitigation for the power sector covering control centers, testing, PPE, and mutual aid.

✅ Control center continuity: segregation, remote ops, reserve shifts

✅ Sequestration triggers, testing priorities, and PPE protocols

✅ Mutual assistance, supply chain risk, and workforce planning

The latest version of the Electricity Subsector Coordinating Council’s (ESCC’s) resource guide to assess and mitigate COVID-19 suggests the U.S. power sector continues to grapple with key concerns involving control center continuity, power plant continuity, access to restricted and quarantined areas, mutual assistance, and supply chain challenges, alongside urban demand shifts seen in Ottawa’s electricity demand during closures.

In its fifth and sixth versions of the “ESCC Resource Guide—Assessing and Mitigating the Novel Coronavirus (COVID-19),” released on April 16 and April 20, respectively, the ESCC expanded its guidance as it relates to social distancing and sequestration within tight power sector environments like control centers, crucial mitigation strategies that are designed to avoid attrition of essential workers.

The CEO-led power sector group that serves as a liaison with the federal government during emergencies introduced the guide on March 23, and it provides periodic updates  sourced from “tiger teams,” which are made up of representatives from investor-owned electric companies, public power utilities, electric cooperatives, independent power producers (IPPs), and other stakeholders. Collating regulatory updates and emerging resources, it serves as a general shareable blueprint for generators,  transmission and distribution (T&D) facilities, reliability coordinators, and balancing authorities across the nation on issues the sector is facing as the COVID-19 pandemic endures.

Controlling Spread at Control Centers
While control centers are typically well-isolated, physically secure, and may be conducive to on-site sequestration, the guide is emphatic that staff at these facilities are typically limited and they need long lead times to be trained to properly use the information technology (IT) and operational technology (OT) tools to keep control centers functioning and maintain grid visibility. Control room operators generally include: reliability engineers, dispatchers, area controllers, and their shift supervisors. Staff that directly support these function, also considered critical, consist of employees who maintain and secure the functionality of the IT and OT tools used by the control room operators.

In its latest update, the ESCC notes that many entities took “proactive steps to isolate their control center facilities from external visitors and non-essential employees early in the pandemic, leveraging the presence of back-up control centers, self-quarantining of employees, and multiple shifts to maximize social distancing.” To ensure all levels of logistical and operational challenges posed by the pandemic are addressed, it envisions several scenarios ranging from mild contagion—where a single operator is affected at one of two control center sites to the compromise of both sites.

Previous versions of the guide have set out universal mitigation strategies—such as clear symptom reporting, cleaning, and travel guidance. To ensure continuity even in the most dire of circumstances, for example, it recommends segregating shifts, and even sequestering a “complete healthy shift” as a “reserve” for times when minimum staffing levels cannot be met. It also encourages companies to develop a backup staff of retirees, supervisors, managers, and engineers that could backfill staffing needs.

Meanwhile, though social distancing has always been a universal mitigation strategy, the ESCC last week detailed what social distancing at a control room could look like. It says, for example, that entities should consider if personnel can do their jobs in spaces adjacent to the existing control room; moving workstations to allow at least six feet of space between employees; or designating workstations for individual operators. The guide also suggests remote operations outside of a single control room as an option, and some markets are exploring virtual power plant models in the UK to support flexibility, though it underscores that not all control center operations can be performed remotely, and remote operations increase the potential for security vulnerabilities. “The NERC [North American Electric Reliability Corp.] Reliability Standards address requirements for BES [bulk electric system] control centers and security controls for remote access of systems, applications, or data,” the resource guide notes.

Sequestration—Highly Effective but Difficult
Significantly, the new update also clarifies circumstances that could “trigger” sequestration—or keeping mission-essential workers at facilities. Sequestration, it notes, “is likely to be the most effective means of reducing risk to critical control center employees during a pandemic, but it is also the most resource- and cost-intensive option to implement.”

It is unclear exactly how many power sector workers are currently being sequestered at facilities. According to the  American Public Power Association (APPA), as of last week, the New York Power Authority was sequestering 82 power plant control room and transmission control operator, amid New York City’s shifting electric rhythms during COVID-19; the Sacramento Municipal Utility District (SMUD) in California had begun sequestering critical employees; and the Electric & Gas Utility at the City of Tallahassee had 44 workers being rotated in and out of sequestration. Another 37 workers from the New York ISO were already being sequestered or housed onsite as of April 9. PJM began sequestering a team of operators on April 11, and National Grid was sequestering 200 employees as of April 12. 

Decisions to trigger sequestration at T&D and other grid monitoring facilities are typically driven by entities’ risk assessment, ESCC noted. Considerations may involve: 

The number of people showing symptoms or testing positive as a percentage of the population in a county or municipality where the control center is sited. One organization, for example, is considering a lower threshold of 10% community infection as a trigger of “officer-level decision” to determine whether to sequester. A higher threshold of 20% “mandates a move to sequestration,” ESCC said.
The number of essential workers showing symptoms or having tested positive. “Acceptable risk should be based on the minimum staffing requirements of the control center and should include the availability of a reserve shift for critical position backfills. For example, shift supervisors are commonly certified in all positions in the control center, and the unavailability of more than one-third of a single organization’s shift supervisors could compromise operations,” it said.
The rate of infection spread across a geographic region. In the April 20 version, the guide removes specific mention that cases are doubling “every 3–5 days or more frequently in some areas.” It now says:  “Considering the rapid spread of COVID-19, special care should be taken to identify the point at which control center personnel are more likely than not to come into contact with an infected individual during their off-shift hours.”
Generator Sequestration Measures Vary
Generators, meanwhile, have taken different approaches to sequester generation operators. Some have reacted to statewide outbreaks, others to low reserves, and others still, as with one IPP, to control exposure to smaller staffs, which cannot afford attrition. The IPP, for example, decided sequestration was necessary because it “did not want to wait for confirmed cases in the workforce.” That company sequestered all its control room operators, outside operators, and instrumentation and control technicians.

The ESCC resource guide says workers are being sequestered in several ways. On-site, these could range from housing workers in two separate areas, for example, or in trailers brought in. Off-site, workers may be housed in hotel rooms, which the guide notes, “are plentiful.”

Location makes a difference, it said: “Onsite requires more logistical co-ordination for accommodations, food, room sanitization, linens, and entertainment.”  To accommodate sequestered workers, generators have to consider off-site food and laundry services (left at gates for pick-up)—and even extending Wi-Fi for personal use. Generators are learning from each other about all aspects of sequestration—including how to pay sequestered workers. It suggests sequestered workers should receive pay for all hours inside the plant, including straight time for regularly scheduled hours and time-and-a-half for all other hours. To maintain non-sequestered employees, who are following stay-at-home protocols, pay should remain regularly scheduled, it says.

Testing Remains a Formidable Hurdle
Though decisions to sequester differ among different power entities, they appear commonly complicated by one prominent issue: a dearth of testing.

At the center of a scuffle between the federal and state governments of late, the number of tests has not kept pace with the severity of the pandemic, and while President Trump has for some weeks claimed that “Testing is a local thing,” state officials, business leaders—including from the power sector—and public health experts say that it is far short of the several hundred thousands or perhaps even millions of daily tests it might take to safely restart the economy, even as calls to keep electricity options open grow among policymakers, a three-phase approach for which the Trump administration rolled out this week. While the White House said the approach is “based on the advice of public health experts, the suggestions do not indicate a specific timeframe. Some hard-hit states have committed to keeping current restrictions in place. New York on April 16 said it would maintain a shutdown order through May 15, while California published its own guidelines and states in the Northeast, Midwest, and West Coast entered regional pacts that may involve interstate coordination on COVID-19–related policy going forward.

On Sunday, responding to a call by governors across the political spectrum that insisted the federal government should step up efforts to help states obtain vital supplies for tests, Trump said the federal government will be “using” and “preparing to use” the Defense Production Act to increase swab production.

For the power entities that are part of the ESCC, widespread testing underlies many mitigation strategies. The group’s generation owners and operating companies, which include members from the full power spectrum, have said testing is central to “successful mitigation of risk to control center continuity.”

In the updated guide, the entities recommend requesting that governmental authorities—it is unclear whether the focus should be on the federal or state governments—“direct medical facilities to prioritize testing for asymptomatic generation control room operators, operator technicians, instrument and control technicians, and the operations supervisor (treat comparable to first responders) in advance of sequestered, extended-duration shifts; and obtain state regulatory approval for corporate health services organizations to administer testing for coronavirus to essential employees, if applicable.”

The second priority, as crucial, involves asking the government to direct medical facilities to prioritize testing for control room operators before they are sequestered or go into extended-duration shifts.

Generators also want local, regional, state, and federal governments to ensure operators of generating facilities are allowed to move freely if “populace-wide quarantine/curfew or other travel restrictions” are enacted. Meanwhile,  they have also asked federal agencies and state permitting agencies to allow for non-compliance operations of generating facilities in case enough workers are not available.

Lower on its list, but still “medium priority,” is that the government should obtain authority for priority supply of sanitizing supplies and personal protective equipment (PPE) for generating facilities. They are also asking states to allow power plant employees (as opposed to crucially redirected medical personnel) to administer health questionnaires and temperature checks without Americans with Disabilities Act or other legal constraints. Newly highlighted in the update, meanwhile, is an emphasis on enough fire retardant (FR) vests and hoods and PPE, including masks and face coverings, so technicians don’t have to share them.

The worst-case scenario envisioned for generators involves a 40% workforce attrition, a nine-month pandemic, and no mutual assistance. As the update suggests, along with universal mitigation strategies, some power companies are eliminating non-essential work that would require close contact, altering assignments so work tasks are done by paired teams that do not rotate, and ensuring workers wear masks. The resource guide includes case studies and lessons learned so far, and all suggest pandemic planning was crucial to response. 

Gearing Up for Mutual Assistance—Even for Generation—During COVID-19
Meanwhile, though the guide recognizes that protecting employees is a key priority for many entities, it also lauds the crucial role mutual assistance plays in the sector’s collective response to the pandemic, even as coal and nuclear plant closures test just transition planning across regions. Mutual assistance is a long-standing power sector practice in the U.S. Last week, for example, as severe weather impacted the southern and eastern portions of the U.S., causing power outages for 1.3 million customers at the peak, the sector demonstrated the “versatility of mutual assistance processes,” bringing in additional workers and equipment from nearby utilities and contractors to assist with assessment and repair. “Crews utilized PPE and social distancing per the CDC [Centers for Disease Control and Prevention] and OSHA [Occupational Safety and Health Administration] guidelines to perform their restoration duties,” the Energy Department told POWER.

But as the ESCC’s guide points out, mutual assistance has traditionally been deployed to help restore electric service to customers, typically focused on T&D infrastructure. The COVID-19 pandemic, uniquely, “has motivated generation entities to consider the use of mutual assistance for generation plant operation” it notes. As with the model it proposes to ensure continuity of control centers, mutual aid poses key challenges, such as for task variance, knowledge of operational practice, system customization, and legal indemnification.

Among guidelines ESCC proposes for generators are to use existing employee work stoppage plans as a resource in planning for the use of personnel not currently assigned to plant operation. It urges, for example, that generators keep a list of workers with skills who can be called from corporate/tech support (such as former operators or plant engineers/managers), or retirees and other individuals who could be called upon to help operate the control room first. ESCC also recommends considering the use of third-party contractor operations to supplement plant operations.

Key to these efforts is to “Create a thorough list of experience and qualifications needed to operate a particular unit. Important details include fuel type, OEM [original equipment manufacturer] technology, DCS [distributed control system] type, environmental controls, certifications, etc,” it says. “Consider proactively sharing this information internally within your company first and then with neighboring companies”—and that includes sufficient detail from manufacturers (such as Emerson Ovation, GE Mark VI, ABB, Honeywell)—“without exposing proprietary information.” One way to control this information is to develop a mutual assistance agreement with “strategic” companies within the region or system, it says.

Of specific interest is that the ESCC also recommends that generators consider “leaving units in extended or planned maintenance outage in that state as long as possible.” That’s because, “Operators at these offline sites could be considered available for a site responding to pandemic challenges,” it says.

However, these guidelines differ by resource. Nuclear generators, for example, already have robust emergency plans that include minimum staffing requirements, and owing to regulations, mutual aid is managed by each license holder, it says. However, to provide possible relief for attrition at operating nuclear plants, the Nuclear Regulatory Commission (NRC) on March 28 outlined a streamlined process that could allow nuclear operators to obtain exemptions from work hour rules, while organizations also point to IAEA low-carbon electricity lessons for future planning.

Uncertainty of Supply Chain Endurance
As the guide stresses, operational continuity during the pandemic will require that all power entities maintain supply of inputs and physical equipment. To help entities plan ahead—by determining volumes needed and geographic location of suppliers—it lists the most important materials needed for power delivery and bulk chemicals. “Clearly, the extent and duration of this emergency will influence the importance of one supply chain component compared to another,” it says.

As Massachusetts Institute of Technology supply chain expert David Simchi-Levi noted on April 13, global supply chains have been heavily taxed by the pandemic, and manufacturing activities in the European Union and North America are still going offline. China is showing signs of slow recovery. Even in the best-case scenario, however—even if North America and Europe manage to control and reduce the pandemic—the supply chain will likely experience significant logistical capacity shortages, from transportation to warehousing. Owing to variability in timing, he suggested that companies plan to reconfigure supply chains and reposition inventory in case suppliers go out of business or face quarantine, while some industry groups urge investing in hydropower as part of resilient recovery strategies.

Also in short supply, according to ESCC, is industry-critical PPE. “While our sector recognizes that the priority is to ensure that PPE is available for workers in the healthcare sector and first responders, a reliable energy supply is required for healthcare and other sectors to deliver their critical services,” its resource guide notes. “The sector is not looking for PPE for the entire workforce. Rather, we are working to prioritize supplies for mission-essential workers – a subset of highly skilled energy workers who are unable to work remotely and who are mission-essential during this extraordinary time.”

Among critical industry PPE needs are nitrile gloves, shoe covers, Tyvek suits, goggles/glasses, hand sanitizer, dust masks, N95 respirators, antibacterial soap, and trashbags. While it provides a list of non-governmental PPE vendors and suppliers, the guide also provides several “creative” solutions. These include, for example, formulations for effective hand sanitizer; 3D printer face shield files; methods for decontaminating face piece respirators and other PPE; and instructions for homemade masks with pockets for high-efficiency particulate air (HEPA) filter inserts.

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Australian Electric Vehicle Sales tripled in 2019 amid expanding charging infrastructure and more models, but market share remains low, constrained by limited government policy, weak incentives, and absent emissions standards despite growing ultra-fast chargers.

Key Points

EV units sold in Australia; in 2019 they tripled to 6,718, but market share was just 0.6%.

✅ Sales rose from 2,216 (2018) to 6,718 (2019); ~80% were BEVs.

✅ Public charging sites reached 2,307; fast chargers up 40% year-on-year.

✅ Policy gaps and absent standards limit model supply and EV uptake.

Sales of electric vehicles in Australia tripled in 2019 despite a lack of government support, according to the industry’s peak body.

The country’s network of EV charging stations was also growing, the Electric Vehicle Council’s annual report found, including a rise in the number of faster charging stations that let drivers recharge a car in about 15 minutes.

But the report, released on Wednesday, found the market share for electric vehicles was still only 0.6% of new vehicle sales – well behind the 2.5% to 5% in other developed countries.

The chief executive of the council, Behyad Jafari, said the rise in sales was down to more models becoming available. There are now 28 electric models on sale, with eight priced below $65,000.

Six more were due to arrive before the end of 2021, including two priced below $50,000, the council’s report said.

“We have repeatedly heard from car companies that they were planning to bring vehicles here, but Australia doesn’t have that policy support.”

The Morrison government promised a national electric vehicle strategy would be finalised by the middle of this year, but the policy has been delayed. The prime minister, Scott Morrison, last year accused Labor of wanting to “end the weekend” and force people out of four-wheel drives after the opposition set a target of 50% of new car sales being electric by 2030.

Jafari cited the Kia e-Niro – an award-winning electric SUV that was being prepared for an Australian launch, but is now reportedly on hold because the manufacturer favoured shipping to countries with emissions standards.

The council’s members include BMW, Nissan, Hyundai and Harley Davidson, as well as energy, technology and charging infrastructure companies.

Sales of electric vehicles – which include plug-in hybrids – went from 2,216 in 2018 to 6,718 in 2019, the report said. Jafari said about 80% of those sales were all-electric vehicles.

There have been 3,226 electric vehicles sold in 2020, the report said, despite an overall drop of 20% in vehicle sales due to the Covid-19 pandemic, while U.S. EV sales have surged into 2024.

Jafari said: “Our report is showing that Australian consumers want these cars.

“There is no controversy that the future of the industry is electric, but at the moment the industry is looking at different markets. We want policies that show [Australia] is going on this journey.”

Government agency data has forecast that half the new cars sold will be electric by 2035, underscoring that the age of electric cars is arriving even if there is no policy to support their uptake.

Manufacturers currently selling electric cars in Australia are Nissan, Hyundai, Mitsubishi, Tesla, Volvo, Porsche, Audi, BMW, Mercedes, Jaguar and Renault, the report said.

Jafari said most G20 countries had emissions standards in place for vehicles sold and incentives in place to support electric vehicles, such as rebates or exemptions from charges. This hadn’t happened in Australia, he said.

The report said: “Globally, carmakers are rolling out more electric vehicle models as the electric car market expands, but so far production cannot keep up with demand. This means that without policy signals, Australians will continue to be denied access to the full global range of electric vehicles.”

On Tuesday, one Australian charging provider, Evie Networks, opened an ultra-fast station at a rest stop at Campbell Town in Tasmania – between Launceston and Hobart.

The company said the station would connect EV owners in the state’s north and south and the two 350kW chargers could recharge a vehicle in 15 minutes, highlighting whether grids have the power to charge EVs at scale. Two more sites were planned for Tasmania, the company said.

A Tasmanian government grant to support electric vehicle charging had helped finance the site. Evie was also supported with a $15m grant from the federal government’s Australian Renewable Energy Agency.

According to the council report, Australia now has 2,307 public charging stations, including 357 fast chargers – a rise of 40% in the past year.

A survey of 2,900 people in New South Wales, the ACT, Victoria and South Australia, carried out by NRMA, RACV and RAA on behalf of the council, found the main barriers to buying an electric vehicle were concerns over access to charging points, higher prices and uncertainty over driving range.

Consumers favoured electric vehicles because of their environmental footprint, lower maintenance costs and vehicle performance.

The report said the average battery range of electric vehicles available in Australia was 400km, but almost 80% of people thought the average was less.

According to the survey, 56% of Australians would consider an electric car when they next bought a vehicle, and in the UK, EV inquiries soared during a fuel supply crisis.

“We are far behind, but it is surmountable,” Jafari said.

The council report also rated state and territories on the policies that supported its industry and found the ACT was leading, followed by NSW and Queensland.

A review of commercial electric vehicle use found public electric bus trials were planned or under way in Queensland, NSW, WA, Victoria and ACT. There are now more than 400,000 electric buses in use around the globe.

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PG&E Wind Shutdown and Renewable Reliability examines PSPS strategy, wildfire risk, transmission line exposure, wind turbine cut-out speeds, grid stability, and California's energy mix amid historic high-wind events and supply constraints across service areas.

Key Points

An overview of PG&E's PSPS decisions, wildfire mitigation, and how wind cut-out limits influence grid reliability.

✅ Wind turbines reach cut-out near 55 mph, reducing generation.

✅ PSPS mitigates ignition from damaged transmission infrastructure.

✅ Baseload diversity improves resilience during high-wind events.

According to the official, widely reported story, Pacific Gas & Electric (PG&E) initiated power shutoffs across substantial portions of its electric transmission system in northern California as a precautionary measure.

Citing high wind speeds they described as “historic,” the utility claims that if it didn’t turn off the grid, wind-caused damage to its infrastructure could start more wildfires.

Perhaps that’s true. Perhaps. This tale presumes that the folks who designed and maintain PG&E’s transmission system are unaware of or ignored the need to design it to withstand severe weather events, and that the Federal Energy Regulatory Commission (FERC) and North American Electric Reliability Corp. (NERC) allowed the utility to do so.

Ignorance and incompetence happens, to be sure, but there’s much about this story that doesn’t smell right—and it’s disappointing that most journalists and elected officials are apparently accepting it without question.

Take, for example, this statement from a Fox News story about the Kincade Fires: “A PG&E meteorologist said it’s ‘likely that many trees will fall, branches will break,’ which could damage utility infrastructure and start a fire.”

Did you ever notice how utilities cut wide swaths of trees away when transmission lines pass through forests? There’s a reason for that: When trees fall and branches break, the grid can still function, and even as the electric rhythms of New York City shifted during COVID-19, operators planned for variability.

So, if badly designed and poorly maintained infrastructure isn’t the reason PG&E cut power to millions of Californians, what might have prompted them to do so? Could it be that PG&E’s heavy reliance on renewable energy means they don’t have the power to send when a “historic” weather event occurs, especially as policymakers weigh the postponed closure of three power plants elsewhere in California?

Wind Speed Limits

The two most popular forms of renewable energy come with operating limitations, which is why some energy leaders urge us to keep electricity options open when planning the grid. With solar power, the constraint is obvious: the availability of sunlight. One doesn’t generate solar power at night and energy generation drops off with increasing degrees of cloud cover during the day.

The main operating constraint of wind power is, of course, wind speed, and even in markets undergoing 'transformative change' in wind generation, operators adhere to these technical limits. At the low end of the scale, you need about a 6 or 7 miles-per-hour wind to get a turbine moving. This is called the “cut-in speed.” To generate maximum power, about a 30 mph wind is typically required. But, if the wind speed is too high, the wind turbine will shut down. This is called the “cut-out speed,” and it’s about 55 miles per hour for most modern wind turbines.

It may seem odd that wind turbines have a cut-out speed, but there’s a very good reason for it. Each wind turbine rotor is connected to an electric generator housed in the turbine nacelle. The connection is made through a gearbox that is sized to turn the generator at the precise speed required to produce 60 Hertz AC power.

The blades of the wind turbine are airfoils, just like the wings of an airplane. Adjusting the pitch (angle) of the blades allows the rotor to maintain constant speed, which, in turn, allows the generator to maintain the constant speed it needs to safely deliver power to the grid. However, there’s a limit to blade pitch adjustment. When the wind is blowing so hard that pitch adjustment is no longer possible, the turbine shuts down. That’s the cut-out speed.

Now consider how California’s power generation profile has changed. According to Energy Information Administration data, the state generated 74.3 percent of its electricity from traditional sources—fossil fuels and nuclear, amid debates over whether to classify nuclear as renewable—in 2001. Hydroelectric, geothermal, and biomass-generated power accounted for most of the remaining 25.7 percent, with wind and solar providing only 1.98 percent of the total.

By 2018, the state’s renewable portfolio had jumped to 43.8 percent of total generation, with clean power increasing and wind and solar now accounting for 17.9 percent of total generation. That’s a lot of power to depend on from inherently unreliable sources. Thus, it wouldn’t be at all surprising to learn that PG&E didn’t stop delivering power out of fear of starting fires, but because it knew it wouldn’t have power to deliver once high winds shut down all those wind turbines

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Pickering Nuclear False Alert Investigation probes Ontario's emergency alert system after a provincewide cellphone, radio, and TV warning, assessing human error, Pelmorex safeguards, Emergency Management Ontario oversight, and communication delays.

Key Points

An Ontario probe into the erroneous Pickering nuclear alert, focusing on human error, system safeguards, and oversight.

✅ Human error during routine testing suspected

✅ Pelmorex safeguards and EMO protocols under review

✅ Two-hour all-clear delay prompts communication fixes

An investigation into a mistaken Pickering alert warning of an incident at the Pickering Nuclear Generating Station will be completed fairly quickly, Ontario's solicitor general said.

Sylvia Jones tapped the chief of Emergency Management Ontario to investigate how the alert warning of an unspecified problem at the facility was sent in error to cellphones, radios and TVs across the province at about 7:30 a.m. Sunday.

"It's very important for me, for the people of Ontario, to know exactly what happened on Sunday morning," said Jones. "Having said that, I do not anticipate this is going to be a long, drawn-out investigation. I want to know what happened and equally important, I want some recommendations on insurances and changes we can make to the system to make sure it doesn't happen again."

Initial observations suggest human error was responsible for the alert that was sent out during routine tests of the emergency alert, Jones said.

"This has never happened in the history of the tests that they do every day, twice a day, but I do want to know exactly all of the issues related to it, whether it was one human error or whether it was a series of things."

Martin Belanger, the director of public alerting for Pelmorex, a company that operates the alert system, said there are a number of safeguards built in, including having two separate platforms for training and live alerts.

"The software has some steps and some features built in to minimize that risk and to make sure that users will be able to know whether or not they're sending an alert through the...training platform or whether they're accessing the live system in the case of a real emergency," he said.

Only authorized users have access to the system and the province manages that, Belanger said. Once in the live system, features make the user aware of which platform they are using, with various prompts and messages requiring the user's confirmation. There is a final step that also requires the user to confirm their intent of issuing an alert to cellphones, radio and TVs, Belanger said.

On Sunday, a follow-up alert was sent to cellphones nearly two hours after the original notification, and similar grid alerts in Alberta underscore timing and public expectations.

NDP energy critic Peter Tabuns is critical of that delay, noting that ongoing utility scam warnings can further erode public trust.

"That's a long time for people to be waiting to find out what's really going on," he said. "If people lose confidence in this system, the ability to use it when there is a real emergency will be impaired. That's dangerous."

Treasury Board President Peter Bethlenfalvy, who represents the riding of Pickering-Uxbridge, said getting that alert Sunday morning was "a shock to the system," and he too wants the investigation to address the reason for the all-clear delay.

"We all have a lot of questions," he said. "I think the public has every right to know exactly what went on and we feel exactly the same way."

People in the community know the facility is safe, Bethlenfalvy said.

"We have some of the safest nuclear assets in the world -- the safest -- at 60 per cent of Ontario's electricity," he said.

A poll released Monday found that 82 per cent of Canadians are concerned about spills from nuclear reactors contaminating drinking water and 77 per cent are concerned about neighbourhood safety and security risks for those living close to nuclear plants. Oraclepoll Research surveyed 2,094 people across the country on behalf of Friends of the Earth between Jan. 2 and 12, the day of the false alert. The have a margin of error of plus or minus 2.1 per cent, 19 times out of 20.

The wording of Sunday's alert caused much initial confusion, and events like a power outage in London show how morning disruptions can amplify concern, warning residents within 10 kilometres of the plant of "an incident," though there was no "abnormal" release of radioactivity and residents didn't need to take protective steps, but emergency crews were responding.

In the event of a real emergency, the wording would be different, Jones said.

"There are a number of different alerts that are already prepared and are ready to go," she said. "We have the ability to localize it to the communities that are impacted, but because this was a test, it went provincewide."

Jones said she expects the results of the probe to be made public.

The Pickering nuclear plant has been operating since 1971, and had been scheduled to be decommissioned this year, but the former Liberal government -- and the current Progressive Conservative government -- committed to keeping it open until 2024. Decommissioning is now set to start in 2028.

It operates six CANDU reactors, generates 14 per cent of Ontario's electricity and is responsible for 4,500 jobs across the region, according to OPG, and OPG's credit rating remains stable.

During the COVID-19 pandemic, Hydro One employees supported the Province of Ontario in the fight against COVID-19.

The Green party is calling on the province to use this opportunity to review its nuclear emergency response plan, including pandemic staffing contingencies, last updated in 2017 and subject to review every five years.

Toronto Mayor John Tory praised Ontario for swiftly launching an investigation, but said communication between city and provincial officials wasn't what it should have been under the circumstances.

"It was a poor showing and I think everybody involved knows that," he said. "We've got to make sure it's not repeated."

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Minnesota Carbon-Free Power by 2050 aims to shift utilities to renewable energy, wind and solar, boosting efficiency while managing grid reliability, emissions, and costs under a clean energy mandate and statewide climate policy.

Key Points

A statewide goal to deliver 100% carbon-free power by 2050, prioritizing renewables, efficiency, and grid reliability.

✅ Targets 100% carbon-free electricity statewide by 2050

✅ Prioritizes wind, solar, and efficiency before fossil fuels

✅ Faces utility cost, reliability, and legislative challenges

Gov. Tim Walz's plan for Minnesota to get 100 percent of its electricity from carbon-free sources by 2050, similar to California's 100% carbon-free mandate in scope, was criticized Tuesday at its first legislative hearing, with representatives from some of the state's smaller utilities saying they can't meet that goal.

Commerce Commissioner Steve Kelley told the House climate committee that the Democratic governor's plan is ambitious. But he said the state's generating system is "aging and at a critical juncture," with plants that produce 70 percent of the state's electricity coming up for potential retirement over the next two decades. He said it will ensure that utilities replace them with wind, solar and other innovative sources, and increased energy efficiency, before turning to fossil fuels.

"Utilities will simply need to demonstrate why clean energy would not work whenever they propose to replace or add new generating capacity," he said.

Walz's plan, announced last week, seeks to build on the success of a 2007 law that required Minnesota utilities to get at least 25 percent of their electricity from renewable sources by 2025. The state largely achieved that goal in 2017 thanks to the growth of wind and solar power, and the topic of climate change has only grown hotter, with some proposals like a fully renewable grid by 2030 pushing even faster timelines, hence the new goal for 2050.

But Joel Johnson, a lobbyist for the Minnkota Power Cooperative, testified that the governor's plan is "misguided and unrealistic" even with new technology to capture carbon dioxide emissions from power plants. Johnson added that even the big utilities that have set goals of going carbon-free by mid-century, such as Minneapolis-based Xcel Energy, acknowledge they don't know yet how they'll hit the net-zero electricity by mid-century target they have set.

Minnkota serves northwestern Minnesota and eastern North Dakota.

Tim Sullivan, president and CEO of the Wright-Hennepin Cooperative Electric Association in the Twin Cities area, said the plan is a "bad idea" for the 1.7 million state electric consumers served by cooperatives. He said Minnesota is a "minuscule contributor" to total global carbon emissions, even as the EU plans to double electricity use by 2050 to meet electrification demands.

"The bill would have a devastating impact on electric consumers," Sullivan said. "It represents, in our view, nothing short of a first-order threat to the safety and reliability of Minnesota's grid."

Isaac Orr is a policy fellow at the Minnesota-based conservative think tank, the Center for the American Experiment, which released a report critical of the plan Tuesday. Orr said all Minnesota households would face higher energy costs and it would harm energy-intensive industries such as mining, manufacturing and health care, while doing little to reduce global warming.

"This does not pass a proper cost-benefit analysis," he testified.

Environmental groups, including Conservation Minnesota and the Sierra Club, supported the proposal while acknowledging the challenges, noting that cleaning up electricity is critical to climate pledges in many jurisdictions.

"Our governor has called climate change an existential crisis," said Kevin Lee, director of the climate and energy program at the Minnesota Center for Environmental Advocacy. "This problem is the defining challenge of our time, and it can feel overwhelming."

Rep. Jean Wagenius, the committee chairwoman and Minneapolis Democrat who's held several hearings on the threats that climate change poses, said she expected to table the bill for further consideration after taking more testimony in the evening and would not hold a vote Tuesday.

While the bill has support in the Democratic-controlled House, it's not scheduled for action in the Republican-led Senate. Rep. Pat Garofalo, a Farmington Republican, quipped that it "has a worse chance of becoming law than me being named the starting quarterback for the Minnesota Vikings."

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Offshore wind power accelerates low-carbon electrification, leveraging floating turbines, high capacity factors, HVDC transmission, and hydrogen production to decarbonize grids, cut CO2, and deliver competitive, reliable renewable energy near demand centers.

Key Points

Offshore wind power uses offshore turbines to deliver low-carbon electricity with high capacity factors and falling costs.

✅ Sea-based wind farms with 40-50% capacity factors

✅ Floating turbines unlock deep-water, far-shore resources

✅ Enables hydrogen production and strengthens grid reliability

The need for affordable low-carbon technologies is greater than ever

Global energy-related CO2 emissions reached a historic high in 2018, driven by an increase in coal use in the power sector. Despite impressive gains for renewables, fossil fuels still account for nearly two-thirds of electricity generation, the same share as 20 years ago. There are signs of a shift, with increasing pledges to decarbonise economies and tackle air pollution, and with World Bank support helping developing countries scale wind, but action needs to accelerate to meet sustainable energy goals. As electrification of the global energy system continues, the need for clean and affordable low-carbon technologies to produce this electricity is more pressing than ever. This World Energy Outlook special report offers a deep dive on a technology that today has a total capacity of 23 GW (80% of it in Europe) and accounts for only 0.3% of global electricity generation, but has the potential to become a mainstay of the world's power supply. The report provides the most comprehensive analysis to date of the global outlook for offshore wind, its contributions to electricity systems and its role in clean energy transitions.

The offshore wind market has been gaining momentum

The global offshore wind market grew nearly 30% per year between 2010 and 2018, benefitting from rapid technology improvements. Over the next five years, about 150 new offshore wind projects are scheduled to be completed around the world, pointing to an increasing role for offshore wind in power supplies. Europe has fostered the technology's development, led by the UK offshore wind sector alongside Germany and Denmark. The United Kingdom and Germany currently have the largest offshore wind capacity in operation, while Denmark produced 15% of its electricity from offshore wind in 2018. China added more capacity than any other country in 2018.

The untapped potential of offshore wind is vast

The best offshore wind sites could supply more than the total amount of electricity consumed worldwide today. And that would involve tapping only the sites close to shores. The IEA initiated a new geospatial analysis for this report to assess offshore wind technical potential country by country. The analysis was based on the latest global weather data on wind speed and quality while factoring in the newest turbine designs. Offshore wind's technical potential is 36 000 TWh per year for installations in water less than 60 metres deep and within 60 km from shore. Global electricity demand is currently 23 000 TWh. Moving further from shore and into deeper waters, floating turbines could unlock enough potential to meet the world's total electricity demand 11 times over in 2040. Our new geospatial analysis indicates that offshore wind alone could meet several times electricity demand in a number of countries, including in Europe, the United States and Japan. The industry is adapting various floating foundation technologies that have already been proven in the oil and gas sector. The first projects are under development and look to prove the feasibility and cost-effectiveness of floating offshore wind technologies.

Offshore wind's attributes are very promising for power systems

New offshore wind projects have capacity factors of 40-50%, as larger turbines and other technology improvements are helping to make the most of available wind resources. At these levels, offshore wind matches the capacity factors of gas- and coal-fired power plants in some regions – though offshore wind is not available at all times. Its capacity factors exceed those of onshore wind and are about double those of solar PV. Offshore wind output varies according to the strength of the wind, but its hourly variability is lower than that of solar PV. Offshore wind typically fluctuates within a narrower band, up to 20% from hour to hour, than solar PV, which varies up to 40%.

Offshore wind's high capacity factors and lower variability make its system value comparable to baseload technologies, placing it in a category of its own – a variable baseload technology. Offshore wind can generate electricity during all hours of the day and tends to produce more electricity in winter months in Europe, the United States and China, as well as during the monsoon season in India. These characteristics mean that offshore wind's system value is generally higher than that of its onshore counterpart and more stable over time than that of solar PV. Offshore wind also contributes to electricity security, with its high availability and seasonality patterns it is able to make a stronger contribution to system needs than other variable renewables. In doing so, offshore wind contributes to reducing CO2 and air pollutant emissions while also lowering the need for investment in dispatchable power plants. Offshore wind also has the advantage of avoiding many land use and social acceptance issues that other variable renewables are facing.

Offshore wind is on track to be a competitive source of electricity

Offshore wind is set to be competitive with fossil fuels within the next decade, as well as with other renewables including solar PV. The cost of offshore wind is declining and is set to fall further. Financing costs account for 35% to 50% of overall generation cost, and supportive policy frameworks are now enabling projects to secure low cost financing in Europe, with zero-subsidy tenders being awarded. Technology costs are also falling. The levelised cost of electricity produced by offshore wind is projected to decline by nearly 60% by 2040. Combined with its relatively high value to the system, this will make offshore wind one of the most competitive sources of electricity. In Europe, recent auctions indicate that offshore wind will soon beat new natural gas-fired capacity on cost and be on a par with solar PV and onshore wind. In China, offshore wind is set to become competitive with new coal-fired capacity around 2030 and be on par with solar PV and onshore wind. In the United States, recent project proposals indicate that offshore wind will soon be an affordable option, even as the 1 GW timeline continues to evolve, with potential to serve demand centres along the country's east coast.

Innovation is delivering deep cost reductions in offshore wind, and transmission costs will become increasingly important. The average upfront cost to build a 1 gigawatt offshore wind project, including transmission, was over $4 billion in 2018, but the cost is set to drop by more than 40% over the next decade. This overall decline is driven by a 60% reduction in the costs of turbines, foundations and their installation. Transmission accounts for around one-quarter of total offshore wind costs today, but its share in total costs is set to increase to about one-half as new projects move further from shore. Innovation in transmission, for example through work to expand the limits of direct current technologies, will be essential to support new projects without raising their overall costs.

Offshore wind is set to become a $1 trillion business

Offshore wind power capacity is set to increase by at least 15-fold worldwide by 2040, becoming a $1 trillion business. Under current investment plans and policies, the global offshore wind market is set to expand by 13% per year, reflecting its growth despite Covid-19 in recent years, passing 20 GW of additions per year by 2030. This will require capital spending of $840 billion over the next two decades, almost matching that for natural gas-fired or coal-fired capacity. Achieving global climate and sustainability goals would require faster growth: capacity additions would need to approach 40 GW per year in the 2030s, pushing cumulative investment to over $1.2 trillion. 

The promising outlook for offshore wind is underpinned by policy support in an increasing number of regions. Several European North Seas countries – including the United Kingdom, Germany, the Netherlands and Denmark – have policy targets supporting offshore wind. Although a relative newcomer to the technology, China is quickly building up its offshore wind industry, aiming to develop a project pipeline of 10 GW by 2020. In the United States, state-level targets and federal incentives are set to kick-start the U.S. offshore wind surge in the coming years. Additionally, policy targets are in place and projects under development in Korea, Japan, Chinese Taipei and Viet Nam.

 The synergies between offshore wind and offshore oil and gas activities provide new market opportunities. Since offshore energy operations share technologies and elements of their supply chains, oil and gas companies started investing in offshore wind projects many years ago. We estimate that about 40% of the full lifetime costs of an offshore wind project, including construction and maintenance, have significant synergies with the offshore oil and gas sector. That translates into a market opportunity of $400 billion or more in Europe and China over the next two decades. The construction of foundations and subsea structures offers potential crossover business, as do practices related to the maintenance and inspection of platforms. In addition to these opportunities, offshore oil and gas platforms require electricity that is often supplied by gas turbines or diesel engines, but that could be provided by nearby wind farms, thereby reducing CO2 emissions, air pollutants and costs.

Offshore wind can accelerate clean energy transitions

Offshore wind can help drive energy transitions by decarbonising electricity and by producing low-carbon fuels. Over the next two decades, its expansion could avoid between 5 billion and 7 billion tonnes of CO2 emissions from the power sector globally, while also reducing air pollution and enhancing energy security by reducing reliance on imported fuels. The European Union is poised to continue leading the wind energy at sea in Europe industry in support of its climate goals: its offshore wind capacity is set to increase by at least fourfold by 2030. This growth puts offshore wind on track to become the European Union's largest source of electricity in the 2040s. Beyond electricity, offshore wind's high capacity factors and falling costs makes it a good match to produce low-carbon hydrogen, a versatile product that could help decarbonise the buildings sector and some of the hardest to abate activities in industry and transport. For example, a 1 gigawatt offshore wind project could produce enough low-carbon hydrogen to heat about 250 000 homes. Rising demand for low-carbon hydrogen could also dramatically increase the market potential for offshore wind. Europe is looking to develop offshore "hubs" for producing electricity and clean hydrogen from offshore wind.

It's not all smooth sailing

Offshore wind faces several challenges that could slow its growth in established and emerging markets, but policy makers and regulators can clear the path ahead. Developing efficient supply chains is crucial for the offshore wind industry to deliver low-cost projects. Doing so is likely to call for multibillion-dollar investments in ever-larger support vessels and construction equipment. Such investment is especially difficult in the face of uncertainty. Governments can facilitate investment of this kind by establishing a long-term vision for offshore wind and by drawing on U.K. policy lessons to define the measures to be taken to help make that vision a reality. Long-term clarity would also enable effective system integration of offshore wind, including system planning to ensure reliability during periods of low wind availability.

The success of offshore wind depends on developing onshore grid infrastructure. Whether the responsibility for developing offshore transmission lies with project developers or transmission system operators, regulations should encourage efficient planning and design practices that support the long-term vision for offshore wind. Those regulations should recognise that the development of onshore grid infrastructure is essential to the efficient integration of power production from offshore wind. Without appropriate grid reinforcements and expansion, there is a risk of large amounts of offshore wind power going unused, and opportunities for further expansion could be stifled. Development could also be slowed by marine planning practices, regulations for awarding development rights and public acceptance issues.

The future of offshore wind looks bright but hinges on the right policies

The outlook for offshore wind is very positive as efforts to decarbonise and reduce local pollution accelerate. While offshore wind provides just 0.3% of global electricity supply today, it has vast potential around the world and an important role to play in the broader energy system. Offshore wind can drive down CO2 emissions and air pollutants from electricity generation. It can also do so in other sectors through the production of clean hydrogen and related fuels. The high system value of offshore wind offers advantages that make a strong case for its role alongside other renewables and low-carbon technologies. Government policies will continue to play a critical role in the future of offshore wind and  the overall pace of clean energy transitions around the world.

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