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DOE RMUC Cybersecurity Program supports rural, municipal, and small investor-owned utilities with grants, technical assistance, grid resilience, incident response, workforce training, and threat intelligence sharing to harden energy systems and protect critical infrastructure.

Key Points

A $250M DOE program providing grants to boost rural and municipal utilities' cybersecurity and incident response.

✅ Grants and technical assistance for grid security

✅ Enhances incident response and threat intel sharing

✅ Builds cybersecurity workforce in rural utilities

The U.S. Department of Energy (DOE) today issued a Request for Information (RFI) seeking public input on a new $250 million program to strengthen the cybersecurity posture of rural, municipal, and small investor-owned electric utilities.

Funded by President Biden’s Bipartisan Infrastructure Law and broader clean energy funding initiatives, the Rural and Municipal Utility Advanced Cybersecurity Grant and Technical Assistance (RMUC) Program will help eligible utilities harden energy systems, processes, and assets; improve incident response capabilities; and increase cybersecurity skills in the utility workforce. Providing secure, reliable power to all Americans, with a focus on equity in electricity regulation across communities, will be a key focus on the pathway to achieving President Biden’s goal of a net-zero carbon economy by 2050. 

“Rural and municipal utilities provide power for a large portion of low- and moderate-income families across the nation and play a critical role in ensuring the economic security of our nation’s energy supply,” said U.S. Secretary of Energy Jennifer M. Granholm. “This new program reflects the Biden Administration's commitment to improving energy reliability and connecting our nation’s rural communities to resilient energy infrastructure and the transformative benefits that come with it.” 

Nearly one in six Americans live in a remote or rural community. Utilities in these communities face considerable obstacles, including difficulty recruiting top cybersecurity talent, inadequate infrastructure, as the aging U.S. power grid struggles to support new technologies, and lack of financial resources needed to modernize and harden their systems. 

The RMUC Program will provide financial and technical assistance to help rural, municipal, and small investor-owned electric utilities improve operational capabilities, increase access to cybersecurity services, deploy advanced cyber security technologies, and increase participation of eligible entities in cybersecurity threat information sharing programs and coordination with federal partners initiatives. Priority will be given to eligible utilities that have limited cybersecurity resources, are critical to the reliability of the bulk power system, or those that support our national defense infrastructure. 

The Office of Cybersecurity, Energy Security, and Emergency Response (CESER), which advances U.S. energy security objectives, will manage the RMUC Program, providing $250 million dollars in BIL funding over five years. To help inform Program implementation, DOE is seeking input from the cybersecurity community, including eligible utilities and representatives of third parties and organizations that support or interact with these utilities. The RFI seeks input on ways to improve cybersecurity incident preparedness, response, and threat information sharing; cybersecurity workforce challenges; risks associated with technologies deployed on the electric grid; national-scale initiatives to accelerate cybersecurity improvements in these utilities; opportunities to strengthen partnerships and energy security support efforts; the selection criteria and application process for funding awards; and more. 

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US Control of Ukraine Nuclear Plants sparks debate over ZNPP, Zaporizhzhia, sovereignty, safety, ownership, and international cooperation, as Washington touts utility expertise, investment, and modernization to protect critical energy infrastructure amid conflict.

Key Points

US management proposal for Ukraine's nuclear assets, notably ZNPP, balancing sovereignty, safety, and investment.

✅ Ukraine retains ownership; any transfer requires parliament approval.

✅ ZNPP safety risks persist amid occupation near active conflict.

✅ International reactions split: sovereignty vs. cooperation and investment.

In a recent phone call with Ukrainian President Volodymyr Zelenskyy, U.S. President Donald Trump proposed that the United States take control of Ukraine's nuclear power plants, including the Zaporizhzhia Nuclear Power Plant (ZNPP), which has been under Russian occupation since early in the war and where Russia is reportedly building power lines to reactivate the plant amid ongoing tensions. Trump suggested that American ownership of these plants could be the best protection for their infrastructure, a proposal that has sparked controversy in policy circles, and that the U.S. could assist in running them with its electricity and utility expertise.

Ukrainian Response

President Zelenskyy promptly addressed Trump's proposal, stating that while the conversation focused on the ZNPP, the issue of ownership was not discussed. He emphasized that all of Ukraine's nuclear power plants belong to the Ukrainian people and that any transfer of ownership would require parliamentary approval . Zelenskyy clarified that while the U.S. could invest in and help modernize the ZNPP, ownership would remain with Ukraine.

Security Concerns

The ZNPP, Europe's largest nuclear facility, has been non-operational since its occupation by Russian forces in 2022. The plant's location near active conflict zones raises significant safety risks that the IAEA has warned of in connection with attacks on Ukraine's power grids, and its future remains uncertain. Ukrainian officials have expressed concerns about potential Russian provocations, such as explosions, especially after UN inspectors reported mines at the Zaporizhzhia plant near key facilities, if and when Ukraine attempts to regain control of the plant.

International Reactions

The proposal has elicited mixed reactions both within Ukraine and internationally. Some Ukrainian officials view it as an opportunistic move by the U.S. to gain control over critical infrastructure, while others see it as a potential avenue for modernization and investment, alongside expanding wind power that is harder to destroy in wartime. The international community remains divided on the issue, with some supporting Ukraine's sovereignty over its nuclear assets and others advocating for a possible agreement on power plant attacks to ensure the plant's safety and future operation.

President Trump's proposal to have the U.S. take control of Ukraine's nuclear power plants has sparked significant controversy. While the U.S. offers expertise and investment, Ukraine maintains that ownership of its nuclear assets is a matter of national sovereignty, even as it has resumed electricity exports to bolster its economy. The situation underscores the complex interplay between security, sovereignty, and international cooperation in conflict zones.

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Ontario Global Adjustment and ICI balance hydro rates, renewable cost shift, and peak demand. Class A and Class B customers face demand response decisions amid pandemic occupancy uncertainty and volatile GA charges through 2022.

Key Points

A pricing model where GA costs and ICI peak allocation shape Class A/B bills, driven by renewables cost shifts.

✅ Renewable cost shift trims GA; larger Class A savings expected.

✅ Class A peak strategy returns; occupancy uncertainty persists.

✅ Class B faces volatile GA; limited levers beyond efficiency.

Ontario’s large commercial electricity customers can approach the looming annual decision about their billing structure for the 12 months beginning July 1 with the assurance of long-term relief on a portion of their costs, amid changes coming for electricity consumers that could affect planning. That’s to be weighed against uncertainties around energy demand and whether a locked-in cost allocation formula that looked favourable in pre-pandemic times will remain so until June 30, 2022.

“The biggest unknown is we just don’t know when the people are coming back,” Jon Douglas, director of sustainability with Menkes Property Management Services, reflected during a webinar sponsored by the Building Owners and Managers Association (BOMA) of Greater Toronto last week. “The occupancy in our office buildings this fall, and going into the new year, could really impact the outcome of the decision.”

After a year of operational upheaval and more modifications to provincial electricity pricing policies, BOMA Toronto’s regularly scheduled workshop ahead of the June 15 deadline for eligible customers to opt into the Industrial Conservation Initiative (ICI) program had a lot of ground to cover. Notably, beginning in January, all commercial customers have seen a reduction in the global adjustment (GA) component of their monthly hydro bills after the Ontario government shifted costs associated with contracted non-hydroelectric renewable supply to reduce the burden on industrial ratepayers from electricity rates to the general provincial account — a move that trims approximately $258 million per month from the total GA charged to industrial and commercial customers. However, they won’t garner the full benefit of that until 2022 since they’re currently repaying about $333 million in GA costs that were deferred in April, May and June of 2020.

Renewable cost shift pares the global adjustment
For now, Ontario government officials estimate the renewable cost shift equates to a 12 per cent discount relative to 2020 prices, even as typical bills may rise about 2% as fixed pricing ends in some cases. Once last year’s GA deferral is repaid at the end of 2021, they project the average Class A customer participating in the ICI program should realize a 16 per cent saving on the total hydro bill, while Class B customers paying the GA on a volumetric per kilowatt-hour (kWh) basis will see a slightly more moderate 15 per cent decrease.

“This is the biggest change to electricity pricing that’s happened since the introduction of ICI,” Tim Christie, director of electricity policy, economics and system planning for Ontario’s Ministry of Energy, Northern Development and Mines, told online workshop attendees. “The government is funding the out-of-market costs of renewables. It does tail off into the 2030s as those contracts (for wind, solar and biomass generation) expire, but over the next eight-ish years, it’s pretty steady at around just over $3 billion per year.”

Extrapolating from 2020 costs, he pegged average electricity costs at roughly 9.1 cents/kWh for Class A commercial customers and 13.2 cents/kWh for Class B, a point of concern for Ontario manufacturers facing high rates as well. However, energy management specialists suggest actual 2021 numbers haven’t proved that out.

“In commercial buildings, we’re averaging 10 to 12 cents for Class A in 2021, and we’re seeing more than that for about 14, 15 cents for Class B,” reported Scott Rouse, managing partner with the consulting firm, Energy@Work.

GA costs for Class B customers dropped nearly 30 per cent in the first four months of 2021 compared to the last four months of 2020, when they averaged 11.8 cents/kWh. Thus far, though, there have been significant month-to-month fluctuations, with a low of 5.04 cents/kWh in February and a high of 10.9 cents/kWh in April contributing to the four-month average of 8.3 cents/kWh.

“In 2020, system-wide GA very often averaged more than $1 billion per month,” Rouse said. “This February it dropped to $500 million, which was really quite surprising. So it is a very volatile cost.”

Although welcome, the renewable cost shift does alter the payback on energy-saving investments, particularly for demand response mechanisms like energy storage. When combined with pandemic-related uncertainty and a series of policy and program reversals alongside calls to clean up Ontario’s hydro policy in recent years, the industry’s appetite for some more capital-intensive technologies appears to be flagging.

“Volatility puts a pause on some of the innovation,” said Terry Flynn, general manager with BentallGreenOak and chair of BOMA Toronto’s energy committee. “It could be a leading edge, but it might be a bleeding edge that won’t bear any fruit because the way the commodity costs are structured will change.”

“There’s kind of a wait-and-see approach on some of these bigger investments,” Douglas concurred.

Industrial Conservation Initiative underpins commercial class divide
Turning to the ICI, Class A customers — defined as those with average monthly energy demand of at least 1 megawatt (MW) — encountered some unexpected changes to the program rules during 2020. Meanwhile, Class B customers — encompassing the vast share of commercial properties smaller than about 350,000 square feet — confront the persistent reality of electricity cost allocation that offloads the burden from larger players onto them.

Through the ICI, participating Class A customers pay a share of the global adjustment that’s prorated to their energy use during the five hours of the period from May 1 to April 30 when the highest overall system demand is recorded. This gives Class A customers the opportunity to lock in a favourable factor for calculating their share of monthly system-wide global adjustment costs if they can successful project and curtail energy loads during those five hours of peak demand. On the flipside, Class B customers pay the remainder of those system-wide costs, on a straightforward per-kWh basis, once Class A payments have been reconciled.

“Class B has sometimes been regarded as the forgotten middle child of the customer classes in Ontario where all the shifted costs in the system kind of pile up,” acknowledged Mark Olsheski, vice president, energy and environment, with Sussex Strategy Group. “Likewise, there can be big unpredictable and uncontrollable swings in the global adjustment rate from month to month and, outside of pure energy efficiency, there really is precious little opportunity or empowerment for a Class B customer to take actions to lower their bills.”

Nevertheless, COVID-19 presents a few extra hiccups for Class A customers this year. Conventionally, late May is when they receive notification of the cost allocation factor that would be used to determine their GA for the upcoming July 1 to June 30 period. This year, though, all current ICI participants will retain the factor they secured by responding to the five hours of peak demand during the 12 months from May 1, 2019 to April 30, 2020 after the Ontario government placed a temporary halt on the peak demand response aspect of the program last summer. Regardless, eligible ICI participants must formally opt into the program by June 15 or they will be billed as Class B customers.

Peak chasing resumes for summer 2021
Since peak demand hours conventionally occur from June to September, Class A customers will once again be studying forecasts intently and preparing to respond via Peak Perks as the heat wave season sets in. That should help alleviate some of the system stresses that arose last summer — prompting policy-makers to reject lobbying for a continued pause on peak demand response.

“The policy rationale was to allow consumers to focus on their operations when recovering from COVID as opposed to reducing peaks. The other issue was that we did not expect the peaks to be high last summer given COVID shutdowns,” Christie recounted. “But due to some hot weather, more people at home and also the lack of ICI response, we saw peaks we haven’t seen in many, many years come up last summer. So the peak hiatus has ended and this summer we’ll be back to responding to ICI as per normal.”

Among Class A customers, owners/managers of office and retail facilities generally have the most to lose from a billing formula tied to the energy demand of more densely occupied buildings in the summer of 2019. However, they could be much more competitively positioned for 2022-23 if their buildings remain below full occupancy and energy demand stays lower than usual this summer.

“Where we can improve is the IESO (Independent Electricity System Operator) and the LDCs (local distribution companies) need to help customers get their real-time data, especially in light of the phantom demand issue, interpret their bills and their Class A versus B scenarios much more easily and comprehensively,” urged Lee Hodgkinson, vice president, technical services, sustainability and ESG, with Dream Unlimited. “ I look for APIs (application programming interface) and direct data flow from the LDCs to the building owners so that we can access that data really easily.”

Given Class A’s historic advantages, few eligible ICI participants are expected to migrate out to Class B. From a sustainability perspective, there’s perhaps more cause to question how the ICI’s 1-MW threshold encourages strategies to move in the other direction.

“You could jack up demand in some buildings and get them into Class A basically by firing up the chillers on the weekend and then pouring cooling outside to get rid of it,” Douglas noted. “That has nothing to do with climate change strategy or sustainability, but it’s a cost- saving strategy, and, sometimes, when you look at the math, it’s hundreds of thousands of dollars you can save.”

Brian Hewson, vice president, consumer protection and industry performance with the Ontario Energy Board (OEB), confirmed the OEB is currently scrutinizing the discrepancy that leaves Class B as the only consumer group with no flexibility to curtail energy load during higher-priced periods, and will be providing advice to the Ministry of Energy. In the interim, that status does, at least, simplify tactics.

“Just reduce your kWh and it doesn’t matter what time of day because you’re paying that fixed rate for 24 hours a day. So if you can curb your demand at night, you get a big bang for your dollar,” Rouse advised.

“We do talk about rates a lot, but if you’re not using it, you’re not paying for it,” Flynn agreed. “A lot of our focus is still on really to try to reduce the number of kilowatts that we use. That seems to be the best thing to do.”

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COVID-19 Electricity Demand Shift flattens New York's load curve, lowers peak demand, and reduces wholesale prices as NYISO operators balance the grid amid stay-at-home orders, rising residential usage, cheap natural gas, and constrained renewables.

Key Points

An industry-wide change in load patterns: flatter peaks, lower prices, and altered grid operations during lockdowns.

✅ NYISO operators sequestered to maintain reliable grid control

✅ Morning and evening peaks flatten; residential use rises mid-day

✅ Wholesale prices drop amid cheap natural gas and reduced demand

At his post 150 miles up the Hudson, Jon Sawyer watches as a stay-at-home New York City stirs itself with each new dawn in this era of covid-19.

He’s a manager in the system that dispatches electricity throughout New York state, keeping homes lit and hospitals functioning, work that is so essential that he, along with 36 colleagues, has been sequestered away from home and family for going on four weeks now, to avoid the disease, a step also considered for Ontario power staff during COVID-19 measures.

The hour between 7 a.m. and 8 a.m. once saw the city bounding to life. A sharp spike would erupt on the system’s computer screens. Not now. The disease is changing the rhythms of the city, and, as this U.S. grid explainer notes, you can see it in the flows of electricity.

Kids are not going to school, restaurants are not making breakfast for commuters, offices are not turning on the lights, and thousands if not millions of people are staying in bed later, putting off the morning cup of coffee and a warm shower.

Electricity demand in a city that has been shut down is running 18 percent lower at this weekday morning hour than on a typical spring morning, according to the New York Independent System Operator, Sawyer’s employer. As the sun rises in the sky, usage picks up, but it’s a slower, flatter curve.

Though the picture is starkest in New York, it’s happening across the country. Daytime electricity demand is falling, even accounting for the mild spring weather, and early-morning spikes are deflating, with similar patterns in Ontario electricity demand as people stay home. The wholesale price of electricity is falling, too, driven by both reduced demand and the historically low cost of natural gas.

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Falling demand will hit the companies that run the “merchant generators” hardest. These are the privately owned power plants that sell electricity to the utilities and account for about 57 percent of electricity generation nationwide.

Closed businesses have resulted in falling demand. Residential usage is up — about 15 percent among customers of Con Edison, which serves New York City and Westchester County — as workers and schoolchildren stay home, while in Canada Hydro One peak rates remain unchanged for self-isolating customers, but it’s spread out through the day. Home use does not compensate for locked-up restaurants, offices and factories. Or for the subway system, which on a pre-covid-19 day used as much electricity as Buffalo.

Hospitals are a different story: They consume twice as much energy per square foot as hotels, and lead schools and office buildings by an even greater margin. And their work couldn’t be more vital as they confront the novel coronavirus.

Knowing that, Sawyer said, puts the ordinary routines of his job, which rely on utility disaster planning, the things about it he usually takes for granted, into perspective.

“Keeping the lights on: It comes to the forefront a little more when you understand, ‘I’m going to be sequestered on site to do this job, it’s so critical,’” he said, speaking by phone from his office in East Greenbush, N.Y., where he has been living in a trailer, away from his family, since March 23.

As coronavirus hospitalizations in New York began to peak in April, emergency medicine physician Howard Greller recorded his reflections. (Whitney Leaming/The Washington Post)
Sawyer, 53, is a former submariner in the U.S. Navy, so he has experience when it comes to being isolated from friends and family for long periods. Many of his colleagues in isolation, who all volunteered for the duty, also are military veterans, and they’re familiar with the drill. Life in East Greenbush has advantages over a submarine — you can go outside and throw a football or Frisbee or walk or run the trail on the company campus reserved for the operators, and every day you can use FaceTime or Skype to talk with your family.

His wife understood, he said, though “of course it’s a sacrifice.” But she grasped the obligation he felt to be there with his colleagues and keep the power on.

“It’s a new world, it’s definitely an adjustment,” said Rich Dewey, the system’s CEO, noting that America’s electricity is safe for now. “But we’re not letting a little virus slow us down.”

There are 31 operators, two managers and four cooks and cleaners all divided between East Greenbush, which handles daytime traffic, and another installation just west of Albany in Guilderland, which works at night. The operators work 12-hour shifts every other day.

Computers recalibrate generation, statewide, to equal demand, digesting tens of thousands of data points, every six seconds. Other computers forecast the needs looking ahead 2½ hours. The operators monitor the computers and handle the “contingencies” that inevitably arise.

They dispatch the electricity along transmission lines ranging from 115,000 volts to 765,000 volts, much of it going from plants and dams in western and northern New York downstate toward the city and Long Island.

They always focus on: “What is the next worse thing that can happen, and how can we respond to that?” Sawyer said.

It’s the same shift and the same work they’ve always done, and that gives this moment an oddly normal feeling, he said. “There’s a routine to it that some of the people working at home now don’t have.”

Medical workers check in with them daily to monitor their physical health and mental condition. So far, there have been no dropouts.

Cheap oil doesn’t mean much when no one’s going anywhere

Statewide, the daily demand for electricity has fallen nearly 9 percent.

The distribution system in New England is looking at a 3 to 5 percent decline; the Mid-Atlantic states at 5 to 7 percent; Washington state at 10 percent; and California by nearly as much. In Texas, demand is down 2 percent, “but even there you’re still seeing drops in the early-morning hours,” said Travis Whalen, a utility analyst with S&P Global Platts.

In the huge operating system that embraces much of the middle of the country, usage has fallen more than 8 percent — and the slow morning surge doesn’t peak until noon.

In New York, there used to be a smaller evening spike, too (though starting from a higher load level than the one in the morning). But that’s almost impossible to see anymore because everyone isn’t coming home and turning on the lights and TV and maybe throwing a load in the laundry all at once. No one goes out, either, and the lights aren’t so bright on Broadway.

California, in contrast, had a bigger spike in the evening than in the morning before covid-19 hit; maybe some of that had to do with the large number of early risers spreading out the morning demand and highlighting electricity inequality that shapes access. Both spikes have flattened but are still detectable, and the evening rise is still the larger.

Only at midnight, in New York and elsewhere, does the load resemble what it used to look like.

The wholesale price of electricity has fallen about 40 percent in the past month, according to a study by S&P Global Platts. In California it’s down about 30 percent. In a section covered by the Southwest Power Pool, the price is down 40 percent from a year ago, and in Indiana, electricity sold to utilities is cheaper than it has been in six years.

Some of the merchant generators “are going to be facing some rather large losses,” said Manan Ahuja, also an analyst with S&P Global Platts. With gas so cheap, coal has built up until stockpiles average a 90-day supply, which is unusually large. Ahuja said he believes renewable generators of electricity will be especially vulnerable because as demand slackens it’s easier for operators to fine-tune the output from traditional power plants.

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As Dewey put it, speaking of solar and wind generators, “You can dispatch them down but you can’t dispatch them up. You can’t make the wind blow or the sun shine.”

Jason Tundermann, a vice president at Level 10 Energy, which promotes renewables, argued that before the morning and evening spikes flattened they were particularly profitable for fossil fuel plants. He suggested electricity demand will certainly pick up again. But an issue for renewable projects under development is that supply chain disruptions could cause them to miss tax credit deadlines.

With demand “on pause,” as Sawyer put it, and consumption more evenly spread through the day, the control room operators in East Greenbush have a somewhat different set of challenges. The main one, he said, is to be sure not to let those high-voltage transmission lines overload. Nuclear power shows up as a steady constant on the real-time dashboard; hydropower is much more up and down, depending on the capacity of transmission lines from the far northern and western parts of the state.

Some human habits are more reliably fixed. The wastewater that moves through New York City’s sewers — at a considerably slower pace than the electricity in the nearby wires — hasn’t shown any change in rhythm since the coronavirus struck, according to Edward Timbers, a spokesman for the city’s Department of Environmental Protection. People may be sleeping a little later, but the “big flush” still arrives at the wastewater treatment plants, about three hours or so downstream from the typical home or apartment, every day in the late morning, just as it always has.
 

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Alberta Ends Renewable Energy Moratorium, accelerating wind and solar deployment while prioritizing grid stability, reliability, and infrastructure upgrades to attract investment, cut emissions, meet climate targets, and integrate renewables into the provincial power system.

Key Points

It is Alberta's decision to lift a pause on new wind and solar projects while enhancing grid reliability.

✅ Resumes wind and solar development across Alberta.

✅ Focuses on grid stability and infrastructure upgrades.

✅ Aims to attract investment and meet climate targets.

The Alberta government has announced the end of a temporary suspension on the development of new renewable energy projects, as the power grid operator prepares to accept green energy bids across the market. This pause, which had been in place since May 2023, was initially implemented to evaluate the effects of rapid growth in renewable energy installations on the province's power grid and overall energy system. However, the decision to lift the moratorium reflects a shift in the government’s approach to balancing energy needs and environmental goals.

The suspension was introduced amid concerns that the swift expansion of wind and solar energy projects, including documented challenges with solar energy expansion in the province, could place undue stress on Alberta's electrical grid and infrastructure. Officials expressed worries about the ability of the grid to handle the increased load and the potential need for upgrades to accommodate new renewable energy sources. The government aimed to assess the implications of this growth and determine appropriate measures to ensure that the energy system could support both existing and future demands.

The moratorium drew significant criticism from various sectors, including renewable energy companies, environmental advocates, and local communities. Critics argued that the pause was detrimental to Alberta's efforts to transition to cleaner energy sources and meet climate targets, citing cases like TransAlta scrapping a wind farm amid policy uncertainty. They pointed out that halting projects could delay investments and job creation associated with the renewable energy sector, potentially impeding progress towards a more sustainable energy future.

In response to these concerns, the Alberta government conducted further reviews and consultations. The decision to cancel the pause reflects the government’s recognition of the importance of advancing renewable energy initiatives while also addressing the need for grid stability and infrastructure development. By ending the moratorium, the government aims to support the continued growth of renewable energy projects and maintain momentum in the shift towards greener energy solutions.

The lifting of the moratorium is expected to have a positive impact on the renewable energy industry in Alberta. Several planned projects that were put on hold can now proceed, leading to renewed investment and economic benefits, including a renewable energy surge that could power 4,500 jobs across the province. The government’s decision signals a commitment to integrating renewable energy sources into the provincial grid in a way that ensures both reliability and sustainability.

Going forward, the Alberta government plans to implement measures to better manage the integration of renewable energy into the existing power infrastructure. This includes addressing any potential challenges related to grid capacity and ensuring that the growth of renewable energy projects aligns with the province's overall energy strategy, as recent federal procurement such as a $500M green electricity contract with an Edmonton company underscores demand that integration efforts must accommodate. The goal is to create a balanced approach that supports the development of clean energy while maintaining the stability and efficiency of the energy system.

The end of the moratorium aligns with Alberta’s broader objectives to reduce greenhouse gas emissions and promote environmental sustainability within a province recognized as a powerhouse for both green energy and fossil fuels in Canada. The government’s approach reflects a willingness to adapt policies and strategies in response to evolving industry needs and environmental priorities. By removing the pause, Alberta demonstrates its commitment to fostering a diverse and resilient energy sector that can meet both current and future demands.

The decision to cancel the moratorium is also seen as a move to reinforce Alberta’s position as a leader in renewable energy development. With the lifting of restrictions, the province can continue to attract investment in clean energy projects, as neighboring jurisdictions such as B.C. streamline clean energy approvals to accelerate deployment, enhance its reputation as a progressive energy market, and contribute to global efforts to address climate change.

In summary, the Alberta government’s decision to lift the pause on renewable energy projects represents a significant shift in its approach to energy policy. The move reflects an acknowledgment of the importance of advancing renewable energy while addressing the practical challenges associated with grid management and infrastructure development. By ending the moratorium, Alberta aims to support the growth of clean energy initiatives and maintain its commitment to sustainability and environmental responsibility.

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Sudbury Electrification and Grid Expansion is driving record power demand, EV charging, renewable energy planning, IESO forecasts, smart grid upgrades, battery storage, and industrial electrification, requiring cleaner power plants and transmission capacity in northern Ontario.

Key Points

Rising electricity demand and clean energy upgrades in Sudbury to power EVs, industry, and a smarter, expanded grid.

✅ IESO projects system size may need to more than double

✅ EVs and smart devices increase peak and off-peak load

✅ Battery storage and V2G can support reliability and resiliency

Sudbury, Ont., is consuming more power than ever, amid an electricity supply crunch in Ontario, according to green energy organizations that say meeting the demand will require cleaner energy sources.

"This is the welfare of the entire city on the line and they are putting their trust in electrification," said David St. Georges, manager of communications at reThink Green, a non-profit organization focused on sustainability in Sudbury.

According to St. Georges, Sudbury and northern Ontario can meet the growing demand for electricity to charge clean power for EVs and smart devices. 

According to the Independent Electricity System Operator (IESO), making a full switch from fossil fuels to other renewable energy sources could require more power plants, while other provinces face electricity shortages of their own.

"We have forecasted that Ontario's electricity system will need significant expansion to meet this, potentially more than doubling in size," the IESO told CBC News in an emailed statement.

Electrification in the industrial sector is adding greater demand to the electrical grid as electric cars challenge power grids in many regions. Algoma Steel in Sault Ste. Marie and ArcelorMittal Dofasco in Hamilton both aim to get electric arc furnaces in operation. Together, those projects will require 630 megawatts.

"That's like adding four cities the size of Sudbury to the grid," IESO said.

Devin Arthur, chapter president of the Electric Vehicle society in Greater Sudbury, said the city is coming full circle with fully electrifying its power grid, reflecting how EVs are a hot topic in Alberta and beyond.

"We're going to need more power," he said.

"Once natural gas was introduced, that kind of switched back, and everyone was getting out of electrification and going into natural gas and other sources of power."

Despite Sudbury's increased appetite for electricity, Arthur added it's also easier to store now as Ontario moves to rely on battery storage solutions.

"What that means is you can actually use your electric vehicle as a battery storage device for the grid, so you can actually sell power from your vehicle that you've stored back to the grid, if they need that power," he said.

Harneet Panesar, chief operating officer for the Ontario Energy Board, told CBC the biggest challenge to going green is seeing if it can work around older infrastructure, while policy debates such as Canada's 2035 EV sales mandate shape the pace of change.

"You want to make sure that you're building in the right spot," he said.

"Consumers are shifting from combustion engines to EV drivetrains. You're also creating more dependency. At a very high level, I'm going to say it's probably going to go up in terms of the demand for electricity."

Fossil fuels are the first to go for generating electricity, said St. Georges.

"But we're not there yet, because it's not a light switch solution. It takes time to get to that, which is another issue of electrification," he said.

"It's almost impossible for us not to go that direction."

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