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Extreme weather is making the grid more prone to outages — and now FirstEnergy’s three Ohio utilities want more leeway on their reliability requirements.
Put simply, FirstEnergy is asking the Public Utilities Commission of Ohio to let Cleveland Electric Illuminating Co., Ohio Edison, and Toledo Edison take longer to restore power when the lights go out. The latter two utilities would also be allowed slightly more frequent outages per customer each year.
Comments regarding the request are due to the utilities commission on Dec. 8, less than three weeks after regulators approved higher electricity rates for hundreds of thousands of northeast Ohio utility customers. An administrative trial, known as an evidentiary hearing, is currently set to start Jan. 21.
Consumer and environmental advocates say it’s unfair to make customers shoulder the burden of lower-quality service, as they have already been paying for substantial grid-hardening upgrades.
“Relaxing reliability standards can jeopardize the health and safety of Ohio consumers,” said Maureen Willis, head of the Office of the Ohio Consumers’ Counsel, which is the state’s legal representative for utility customers. “It also shifts the costs of more frequent and longer outages onto Ohioans who already paid millions of dollars to utilities to enhance and develop their distribution systems.”
The United States has seen a rise in blackouts linked to severe weather, a 2024 analysis by Climate Central found, with about twice as many such events happening from 2014 through 2023 compared to the 10 years from 2000 through 2009.
The duration of the longest blackouts has also grown. As of mid-2025, the average length of 12.8 hours represents a jump of almost 60% from 2022, J.D. Power reported in October.
Ohio regulators have approved less stringent reliability standards before, notably for AES Ohio and Duke Energy Ohio, where obligations from those or other orders required investments and other actions to improve reliability.
Some utilities elsewhere in the country have also sought leeway on reliability expectations. In April, for example, two New York utilities asked to exclude some outages related to tree disease and other factors from their performance metrics, which would in effect relax their standards.
Other utilities haven’t necessarily pursued lower targets, but have nonetheless noted vulnerabilities to climate change or experienced more major events that don’t count toward requirements.
FirstEnergy’s case is particularly notable because the company has slow-rolled clean energy and energy efficiency, two tools that advocates say can cost-effectively bolster grid reliability and guard against weather-related outages.
There is also a certain irony to the request: FirstEnergy’s embrace of fossil fuels at the expense of clean energy and efficiency measures has let its subsidiaries’ operations and others continue to emit high levels of planet-warming carbon dioxide. Now, the company appears to nod toward climate-change-driven weather variability as justification for relaxed reliability standards.
FirstEnergy filed its application to the Public Utilities Commission last December, while its recently decided rate case and other cases linked to its House Bill 6 corruption scandal were pending. FirstEnergy argues that specific reliability standards for each of its utilities should start with an average of the preceding five years’ performance. From there, FirstEnergy says the state should tack on extra allowances for longer or more frequent outages to “account for annual variability in factors outside the Companies’ control, in particular, weather impacts that can vary significantly on a year-to-year basis.”
“Honestly, I don’t know of a viable hypothesis for this increasing variability outside of climate change,” said Victoria Petryshyn, an associate professor of environmental studies at the University of Southern California, who grew up in Ohio.
In summer, systems are burdened by constant air-conditioning use during periods of extreme heat and humidity. In winter, frigid air masses resulting from disruptions to the jet stream can boost demand for heat and “cause extra strain on the grid if natural-gas lines freeze,” Petryshyn said.
“All the weather becomes supercharged,” Petryshyn said. “We can all expect stronger storms, stronger winds, and more frequent extreme weather that threatens grid stability.”
FirstEnergy has a long history of obstructing measures that would both reduce greenhouse gas emissions and alleviate stress on the power grid.
In February 2024, the company abandoned its interim 2030 goals for cutting greenhouse gas emissions and said it would continue running two West Virginia coal plants. Before that, FirstEnergy backed plans to weaken Ohio’s energy-efficiency goals. And during the first Trump administration, the company urged the Department of Energy to use emergency powers to keep unprofitable coal and nuclear plants running.
FirstEnergy also spent roughly $60 million on efforts to get lawmakers to pass and protect House Bill 6, the law at the heart of Ohio’s largest utility corruption scandal. HB 6’s nuclear and coal bailouts have since been repealed, but the state’s clean-energy standards remain gutted.
Meanwhile, regulators have let FirstEnergy’s utilities charge customers millions of dollars for grid modernization, “which are supposed to support the utility’s ability to adapt and improve the electric grid to rigging challenges from climate change,” said Karin Nordstrom, a clean-energy attorney with the Ohio Environmental Council.
“However, FirstEnergy has not provided the same investment in energy-efficiency programs, which can help manage rising demand at lower cost than expensive capital investment,” Nordstrom said. FirstEnergy should fully exhaust those tools and customer-funded grid-modernization investments before regulators relax the company’s requirements, she added.
Limited transparency makes FirstEnergy’s plan even more problematic, according to Shay Banton, a regulatory program engineer and energy justice policy advocate for the Interstate Renewable Energy Council. Earlier this year, Banton reported on grid disparities in FirstEnergy’s service territories that leave some areas more prone to outages.
“It feels too early for them to request leniency without proposing or implementing more comprehensive mitigations based on a detailed understanding of the root cause,” Banton said.
It’s also likely that FirstEnergy’s rate increase of nearly $76 million for Cleveland Electric Illuminating Co.’s roughly 745,000 customers, approved on Nov. 19, already accounts for some weather-related factors. This summer, spokesperson Hannah Catlett told Canary Media that “the Illuminating Co. service territory generally sees bigger storm impacts” than areas served by FirstEnergy’s other Ohio utilities.
“Our request to adjust the reliability standards is not a step back in our commitment,” Catlett told Canary Media this fall. “We are confident in the progress underway and remain focused on improving reliability through continued investment in the communities we are privileged to serve.”
But fundamentally, additional leeway for weather variation is unnecessary, said Ashley Brown, a former Ohio utility commissioner and former executive director of the Harvard Electricity Policy Group. Averaging utility performance over several years — the way most regulators do as part of setting reliability standards — should already account for that.
“In fact, the standard should always be going up,” Brown added. “You should expect more productivity from the company.”
In 2017, the early leaders in energy storage made an audacious bet: 35 gigawatts of the new grid technology would be installed in the United States by 2025.
That goal sounded improbable even to some who believed that storage was on a growth trajectory. A smattering of independent developers and utilities had managed to install just 500 megawatts of batteries nationwide, equivalent to one good-size gas-fired power plant. Building 35 gigawatts would entail 70-fold growth in just eight years.
The number didn’t come out of thin air, though. The Energy Storage Association worked with Navigant Research to model scenarios based on a range of assumptions, recalled Praveen Kathpal, then chair of the ESA board of directors. The association decided to run with the most aggressive of the defensible scenarios in its November 2017 report.
In 2021, ESA agreed to merge with the American Clean Power Association and ceased to exist. But, somehow, its boast proved not self-aggrandizing but prophetic.
The U.S. crossed the threshold of 35 gigawatts of battery installations this July and then passed 40 gigawatts in the third quarter, according to data from the American Clean Power Association. The group of vendors, developers, and installers who just eight years ago stood at the margins of the power industry is now second only to solar developers in gigawatts built per year. Storage capacity outnumbers gas power in the queues for future grid additions by a factor of 6.5, according to data compiled by Lawrence Berkeley National Laboratory.
“Storage has become the dominant form of new power addition,” Kathpal said. “I think it’s fair to say that batteries are how America does capacity.”
Back in 2017, I was covering the young storage industry for an outlet called Greentech Media, a beat that was complicated by how little was happening. There was much to write about the “enormous potential” of energy storage to make the grid more reliable and affordable, but it required caveats like “if states change their grid regulations to allow this new technology to compete fairly on its merits, yada yada yada.”
Those batteries that did get built in 2017 look tiny by today’s standards. The locally owned utility cooperative in Kauai built a trailblazing 13-megawatt/52-megawatt-hour battery, the first such utility-scale system designed to sit alongside a solar power plant. And 2017 saw the tail end of the Aliso Canyon procurement, a foundational trial for the storage industry in which developers built a series of batteries in Southern California in just a handful of months to shore up the grid after a record-busting gas leak — adding up to about 100 megawatts.
“You saw green shoots of a lot of where the industry has gone,” said Kathpal.
California passed a law creating a storage mandate in 2010, then found a pressing need for the technology to neutralize the threat of summertime power shortages. Kauai’s small island grid quickly hit a saturation point with daytime solar, so the utility wanted a battery to shift that clean power into the nighttime. These installations weren’t research projects; they were solving real grid problems. But they were few and far in between.
Kathpal recalled one moment that encapsulated the storage industry’s early lean era. At the time, he was developing storage projects for the independent power producer AES. One night around midnight, he parked a rented Camry off a dirt road and pointed a flashlight through a sheet of rain. It was his last stop on a trip to evaluate potential lease sites for grid storage ahead of a utility procurement — looking at available space, proximity to the grid, and stormwater characteristics. But once the utility saw the bids, it decided not to install any batteries after all.
“The storage market is built not only from Navigant reports but also from moments like that,” he said. “We had to lose a lot of projects before we started winning.”
Now that same utility is putting out a call for storage near its substations — exactly the kind of setting Kathpal had toured in the rain all those years ago.
Indeed, many of the projects connected to the grid this year started with developers anticipating future grid needs and putting money on the line for storage back around the time ESA was formulating its big goal, said Aaron Zubaty, CEO of early storage developer Eolian.
“Eolian began developing projects around major metro areas in the western U.S. starting in 2016 and putting the queue positions in that then became operational in 2025,” Zubaty said. The 200-megawatt Seaside battery site at a substation in Portland, Oregon, is one example.
Though the storage industry pioneers somehow nailed the 35-gigawatt goal, market growth defied their expectations in several important ways.
ESA had expected more of a steady ramp to the 35 gigawatts, said Kelly Speakes-Backman, who served as its chief executive officer from 2017 to 2021. But the storage market ran into plenty of false starts, such as when states passed mandates to install batteries but never enforced them, and when federal regulators ordered wholesale markets to incorporate storage but regional implementation dragged on for years.
The ESA report predicted that 2018 deployments would cross the 1-gigawatt threshold, which didn’t actually happen until 2020. But real installations significantly outpaced the expected numbers in the run-up to 2025. The group hoped to hit 9.2 gigawatts installed this year, and instead the industry is on track to deliver 15 gigawatts.
“Once it hit, it really hit,” Speakes-Backman said.
The regional breakdown of storage growth didn’t play out as ESA expected, either. The analysis anticipated that the Northeast would install more than 10 gigawatts, nearly as much as the Southwest (including California and Hawaii); after all, it noted, New England states had passed “aggressive greenhouse gas reduction policies.”
In fact, the Northeast has done exceedingly little to build large-scale storage. (Zubaty told me that “largely dysfunctional power markets combined with utilities that have excessive regulatory capture” thwarted many good battery projects there.)
But other regions surpassed ESA’s expectations. California, Texas, and Arizona alone hold roughly 80% of all U.S. battery storage capacity. This lopsided concentration of storage could be seen as a weakness of the industry. Noah Roberts, executive director of the recently formed Energy Storage Coalition, which advocates for storage in federal arenas, said the pattern reflects how storage has sprung up in spots that suffer acute grid stress.
“Where energy storage has been deployed to date, it is and has been concentrated in areas that have had the greatest reliability need,” he said. “That is Texas and California, where in the early 2020s there were blackouts or brownouts that were quite significant.”
Now, Roberts said, other regions can look at California and Texas for empirical data on how the storage influx has helped reliability while lowering grid costs, for instance by avoiding power scarcity during heat waves and pushing down peak prices. “We’re really seeing the broadening of the geographic footprint of energy storage deployment,” he said, to regions like the Midwest and the mid-Atlantic, which are grappling with unanticipated load growth.
Indeed, the ESA did not foresee the artificial intelligence boom sending power demand through the roof. Instead, its report predicted, “Electrified transportation will likely provide the largest source of new system load.” Now the storage industry has emerged as the biggest player in constructing firm, on-demand power plants, at the exact time that rapid power construction has become the key limiting factor in the AI arms race.
The storage market outdid expectations in one other major way. In 2017 the storage industry was intently focused on getting batteries installed, not so much on where they came from. Since then, bipartisan sentiment has shifted from unfettered global trade to a distinct preference for American manufacturing. The U.S. has made batteries for electric vehicles for years now, but the lithium iron phosphate (LFP) batteries favored for grid storage have come almost exclusively from China. Now manufacturers are opening domestic cell production for grid storage, just in time for new rules that constrain federal tax credits for battery projects with too much material from China.
LG Energy Solution opened a factory to produce battery cells for grid storage in Michigan this summer that is capable of producing up to 16.5 gigawatt-hours at full capacity; the company expects to raise its North America capacity to 40 gigawatt-hours by the end of 2026. “All of our projects integrated before 2022 combined are smaller than some of our newer individual projects,” noted Tristan Doherty, chief product officer of LG Energy Solution subsidiary Vertech, which focuses on grid batteries.
Tesla is opening domestic LFP battery fabrication in 2026. Fluence announced the first shipment of its “domestically manufactured energy storage system” in September. Newcomers with novel chemistries for longer-duration storage are joining the fray, such as Form Energy and Eos Energy, both of which operate factories outside Pittsburgh.
“By the end of next year, we anticipate reaching the milestone of producing as many domestic energy storage battery cells as we need for demand,” Roberts said. “That is a pretty miraculous story that not many industries have the ability to say they’re able to accomplish.”
The storage industry was vindicated in stretching its aspirations beyond what many thought was possible. Those early adopters knew their technology was valuable, but even they didn’t guess how it would connect with the generational forces reshaping the U.S. economy, from AI to the onshoring of industry.
A clarification was made on Dec. 4, 2025: This story has been updated to reflect that LG Energy Solution’s goal to reach 40 GWh of battery-manufacturing capacity is for North America as a whole, not just for the company’s Michigan plant.
Big companies have spent years pushing Georgia to let them find and pay for new clean energy to add to the grid, in the hopes that they could then get data centers and other power-hungry facilities online faster.
Now, that concept is tantalizingly close to becoming a reality, with regulators, utility Georgia Power, and others hammering out the details of a program that could be finalized sometime next year. If approved, the framework could not only benefit companies but also reduce the need for a massive buildout of gas-fired plants that Georgia Power is planning to satiate the artificial intelligence boom.
Today, utilities are responsible for bringing the vast majority of new power projects online in the state. But over the past two years, the Clean Energy Buyers Association has negotiated to secure a commitment from Georgia Power that “will, for the first time, allow commercial and industrial customers to bring clean energy projects to the utility’s system,” said Katie Southworth, the deputy director for market and policy innovation in the South and Southeast at the trade group, which includes major hyperscalers like Amazon, Google, Meta, and Microsoft.
The terms of the commitment were first sketched out in a letter agreement between Georgia Power and CEBA last year and then codified in a July settlement agreement between the utility, staff at the Georgia Public Service Commission, and other stakeholders that cemented the utility’s long-term integrated resource plan.
The “customer-identified resource” (CIR) option will allow hyperscalers and other big commercial and industrial customers to secure gigawatts of solar, batteries, and other energy resources on their own, not just through the utility.
Letting data centers procure their own energy resources could solve a lot of problems for utilities — like the risk of sticking their customers with the cost of building power plants that may be unneeded if the AI boom goes bust. That’s a real concern for Georgia Power, which plans to spend more than $15 billion to build 10 gigawatts of new gas plants and batteries by 2031. This move could dramatically increase customers’ bills and is almost entirely motivated by gigantic — yet highly uncertain — projections of how much energy that data centers will need.
The tech giants behind most of those data centers could also benefit from being able to track down their own clean energy. The carbon-free resources would not only help in meeting hyperscalers’ aggressive climate targets; they are also likely to be cheaper and faster to build than gas plants, which face yearslong backlogs and rising costs.
The CIR option isn’t a done deal yet. Once Georgia Power, the Public Service Commission, and others work out how the program will function, the utility will file a final version in a separate docket next year.
And the plan put forth by Georgia Power this summer lacks some key features that data center companies want. A big point of contention is that it doesn’t credit the solar and batteries that customers procure as a way to meet future peaks in power demand — the same peaks Georgia Power uses to justify its gas-plant buildout.
But as it stands, CEBA sees “the approved CIR framework as a meaningful step toward the ‘bring-your-own clean energy’ model,” Southworth said — a model that goes by the catchy acronym BYONCE in clean-energy social media circles.
The CIR option is technically an addition to Georgia Power’s existing Clean and Renewable Energy Subscription (CARES) program, which requires the utility to secure up to 4 gigawatts of new renewable resources by 2035. CARES is a more standard “green tariff” program that leaves the utility in control of contracting for resources and making them available to customers under set terms, Southworth explained.
Under the CIR option, by contrast, large customers will be able to seek out their own projects directly with a developer and the utility. Georgia Power will analyze the projects and subject them to tests to establish whether they are cost-effective. Once projects are approved by Georgia Power, built, and online, customers can take credit for the power generated, both on their energy bills and in the form of renewable energy certificates. Georgia Power’s current plan allows the procurement of up to 3 gigawatts of customer-identified resources through 2035.
Letting big companies contract their own clean power is far from a new idea. Since 2014, corporate clean-energy procurements have surpassed 100 gigawatts in the United States, equal to 41% of all clean energy added to the nation’s grid over that time, according to CEBA. Tech giants have made up the lion’s share of that growth and have continued to add more capacity in 2025, despite the headwinds created by the Trump administration and Republicans in Congress.
But most of that investment has happened in parts of the country that operate under competitive energy markets, in which independent developers can build power plants and solar, wind, and battery farms. The Southeast lacks these markets, leaving large, vertically integrated utilities like Georgia Power in control of what gets built. Perhaps not coincidentally, Southeast utilities also have some of the country’s biggest gas-plant expansion plans.
A lot of clean energy projects could use a boost from power-hungry companies. According to the latest data from the Southern Energy Renewable Association trade group, more than 20 gigawatts of solar, battery, and hybrid solar-battery projects are now seeking grid interconnection in Georgia.
“The idea that a large customer can buy down the cost of a clean energy resource to make sure it’s brought onto the grid to benefit them and everybody else, because that’s of value to them — that’s theoretically a great concept,” said Jennifer Whitfield, senior attorney at the Southern Environmental Law Center, a nonprofit that’s pushing Georgia regulators to find cleaner, lower-cost alternatives to Georgia Power’s proposed gas-plant expansion. “We’re very supportive of the process because it has the potential to be a great asset to everyone else on the grid.”
Isabella Ariza, staff attorney at the Sierra Club’s Beyond Coal Campaign, said CEBA deserves credit for working to secure this option for big customers in Georgia. In fact, she identified it as one of the rare bright spots offsetting a series of decisions from Georgia Power and the Public Service Commission that environmental and consumer advocates fear will raise energy costs and climate pollution.
“They’re proposing something that makes total sense and would help some companies be able to say ‘We’re powering our stuff with 100% clean energy,’” Ariza said of the CIR option. That’s particularly important at a time when many hyperscalers are backing away from their clean energy targets in their hunt for power for AI data centers, she noted.
Despite those benefits, the CIR framework’s omissions are substantial enough that CEBA did not join stakeholders like Walmart, the Georgia Association of Manufacturers, and the Southern Renewable Energy Association trade groups in signing on to it.
CEBA wanted companies to be able to procure a full range of carbon-free generation resources — such as geothermal and small modular nuclear reactors — rather than just renewable energy and renewables paired with batteries. The trade group also sought a pathway for customers to bring projects forward on a rolling basis more quickly than the current settlement agreement would allow.
But one of the biggest issues CEBA has with the current CIR plan is that it “does not recognize the full capacity value of customer-funded clean, firm resources to the grid,” Southworth said. Capacity value is a measure of how power plants, batteries, and other resources meet peak power demands during the handful of hours per year that determine how much generation and grid infrastructure utilities need to build.
That’s a significant gap. If the resources that big customers secure under the CIR aren’t considered part of the solution to this challenge — if their capacity value isn’t factored in — they may not be able to reduce Georgia Power’s need for gigawatts of gas-fired power plants, which are the traditional utility backstop for ensuring adequate energy supplies.
This would be bad for Georgia Power customers at large, who would end up paying for more gas plants than are actually needed after the data centers driving up power demand secure their own resources instead. It could also saddle data centers and other big customers with growing capacity-related costs that their self-secured projects could otherwise help reduce.
“A well-designed CIR program that recognizes the capacity value of customer-funded clean resources is a win-win-win for large customers, Georgia Power, and all ratepayers,” Southworth said. “Participating customers pay the incremental cost of new clean, firm projects; the utility gets capacity it can count on; and nonparticipating customers benefit from a more diverse, less gas-dependent resource mix without taking on the full cost or fuel price risk of those projects.”
CEBA has ideas for how Georgia Power could financially compensate customers for the capacity value of the resources that they procure. The utility already calculates “avoided capacity values” for the renewable energy, battery, and fossil-fueled resources it brings to the table in its requests for proposals. Georgia Power could provide a capacity credit of similar value to subscribing customers for the projects they procure.
CEBA will “continue to work with the company and commission staff,” Southworth said. Her group sees Georgia Power’s long-term plan approved this summer “as establishing the floor, not the ceiling, for what CIR can become.”
A big shift at the Public Service Commission could lay the groundwork for a reassessment of the program. Last month, Georgia voters elected two Democratic challengers — health care consultant Alicia Johnson and clean-energy advocate Peter Hubbard — to replace Republican incumbents Tim Echols and Fitz Johnson.
The two new commissioners have both pledged to tackle high and rising electricity costs for Georgia Power residential customers. Across the country, utilities and regulators are striving to force data center developers to take on the costs they’re imposing on power grids, rather than foisting them on everyday utility customers.
“Capacity is still an open question” that the Public Service Commission can take up as it decides on the CIR option, said Whitfield of the Southern Environmental Law Center. “Georgia Power is certainly on record that they don’t prefer it to be accredited, which makes sense for them. They want to build more and profit more,” as a regulated utility that earns guaranteed profits on its capital investments. “But that is going to be very much a live issue.”
Since spring of last year, North Carolina’s largest utility has been testing whether household batteries can help the electric grid in times of need — and now the company wants to roll out the plan to businesses, local governments, and nonprofits, too.
Duke Energy has already paid hundreds of North Carolinians to let it tap power from their home storage systems when electricity demand is highest. It’s Duke’s first foray into running a “virtual power plant,” in which the company manages electricity produced and stored by consumers, much as it would control generation from its own facilities.
In September, the utility proposed a similar model for its nonresidential customers, asserting that the scheme will save money by shrinking the need for new power plants and expensive upgrades to the grid. The recognition signals a way forward for distributed renewable energy and storage as state and national politicians back away from the clean energy transition.
The initiative now needs approval from the five-member North Carolina Utilities Commission, where the virtual-power-plant model has faced some skepticism. But the apparent merits of Duke’s plan, which has broad backing, may be too enticing for commissioners to ignore — especially when the state is grappling with rising rates and voracious demand from data centers and other heavy electricity users.
“In an era of massive load growth, something that should lower costs to customers while helping meet peak demand — to me, it’s an absolute no-brainer,” said Ethan Blumenthal, regulatory counsel for the North Carolina Sustainable Energy Association, an advocacy group. “I’m hopeful that [regulators] see it the same way.”
Duke’s trial residential battery incentives grew out of a compromise with rooftop solar installers. Like many investor-owned utilities around the country, the company sought to lower bill credits for the electrons that solar owners add to the grid. When the solar industry and clean energy advocates fought back, the scheme dubbed PowerPair was born.
The test program provides rebates of up to $9,000 for a battery paired with rooftop photovoltaic panels. It’s capped at roughly 6,000 participants, or however many it takes to reach a limit of 60 megawatts of solar. Half of the households agree to let Duke access their batteries 30 to 36 times each year, earning an extra $37 per month on average; the other half enroll in electric rates that discourage use when demand peaks.
The incentives have been crucial for rooftop solar installers, who’ve faced a torrent of policy and macroeconomic headwinds this year, and they’ve proved vital for customers who couldn’t otherwise afford the up-front costs of installing cheap, clean energy.
But the PowerPair enrollees already make up 30 megawatts in one of Duke’s two North Carolina utility territories and could hit their limit in the central part of the state early next year, leaving both consumers and the rooftop solar industry anxious about what’s next.
Duke’s latest proposal for nonresidential customers — which, unlike the PowerPair test, would be permanent — is one answer.
The proposed program is similar to PowerPair in that it’s born of compromise: Last summer, the state-sanctioned customer advocate, clean energy companies, and others agreed to drop their objections to Duke’s carbon-reduction plan under several conditions, including that the utility develop incentives for battery storage for commercial and industrial customers. The Utilities Commission later blessed the deal.
“This was pursuant to the settlement in last year’s carbon plan,” said Blumenthal, “so it’s been a long time coming.”
While many industry and nonprofit insiders refer to the scheme as “Commercial PowerPair,” its official title is the Non-Residential Storage Demand Response Program.
That name reflects the incentives’ focus on storage, with solar as only a minor factor: Duke wants to offer businesses, local governments, and nonprofits $120 per kilowatt of battery capacity installed on its own and just $30 more if it’s paired with photovoltaics.
The maximum up-front inducement of $150 per storage kilowatt is much less than the $360 per kilowatt offered under PowerPair. But more significant for nonresidential customers could be monthly bill credits: about $250 for a 100-kilowatt battery that could be tapped 36 times a year, plus extra if the battery is actually discharged.
Unlike households participating in PowerPair, which must install solar and storage at the same time to get rebates, nonresidential customers can also get the incentives for adding a battery to pair with existing solar arrays.
“That could be very important for municipalities around North Carolina that have already installed a very significant amount of solar, but very little of that is paired with battery storage,” said Blumenthal.
Duke has high hopes for the program, projecting some 500 customers to enroll. Five years in, the resulting 26 megawatts of battery storage would help it avoid building nearly 28 megawatts of new power plants to meet peak demand, saving over $13.6 million. That’s significantly more than the cost of providing and administering the incentives, which Duke places at nearly $11.8 million.
“The Program provides a source of cost-effective capacity that the Company’s system operators can use at their discretion in situations to deliver economic benefits for all customers,” Duke said in its September filing to regulators. “Importantly, the Company received positive feedback from its customers … when sharing the details of the Program.”
Indeed, the proposal has been met with support not just from the Sustainable Energy Association and other clean energy groups but also organizations like the North Carolina Justice Center, which advocates for low-income households. It earned praise from local governments represented by the Southeast Sustainability Directors Network and conditional support from the state-sanctioned customer advocate, known as Public Staff, too.
The good vibes continued last week, when Duke responded positively to detailed suggestions from these parties on how to improve the program. That included a request from Public Staff that the company raise the per-customer limit on battery capacity to align with the maximum amount of solar that a business or other nonresidential consumer can connect to the grid, which is currently 5 megawatts.
“Larger batteries sited at larger customer sites can help provide more significant system benefits and can reduce the need for incremental utility-owned energy storage installed at all ratepayers’ expense,” the agency told regulators in its November comments. It recommends a cap tied to a customer’s peak demand; for example, a business that consumes more energy at once should get incentives for a bigger battery. Duke agreed in its Dec. 5 comments, calling that limit “reasonable.”
Still, questions remain about how to make the incentives most impactful.
Public Staff, for instance, believes Duke should increase its monthly payment to customers for keeping their batteries charged and ready to deploy. This “capacity credit” is now set at $3.50 per kilowatt but effectively reduced to $2.48, because the utility assumes that a percentage of users won’t properly maintain their systems, based on its experience with households. The company calls that a “capability factor,” but the agency dubs it “collective punishment” for all customers and says it should be eliminated or recalibrated for “more sophisticated” nonresidential participants.
Raleigh, North Carolina–based 8MSolar, a member of the Sustainable Energy Association, is among the many installers that have been eagerly anticipating Duke’s proposal.
The program on its own likely won’t “move the needle unless the incentives get bumped up,” said Bryce Bruncati, the company’s director of sales. However, the scheme could tip the scales for large customers when stacked on top of two federal tax opportunities: a 30% incentive available through the end of 2027 and a deduction tied to the depreciation value of the system — up to 100% thanks to the Republican budget law passed this summer.
“The combined three could really have a big impact for small- to medium-sized commercial projects,” Bruncati said. The Duke program would represent “a little bit of icing on the cake.”
Whatever their size and design, the fate of the incentives rests entirely with the Utilities Commission, now that the final round of comments from Duke and other stakeholders is in. There’s no timeline for a decision.
At least one commissioner, Tommy Tucker, has voiced skepticism about leveraging customer-owned equipment to serve the grid at large. “I’m not a big fan of the [demand-side management] or virtual power plants because you’re dependent upon somebody else,” the former Republican state senator said at a recent hearing, albeit one not connected to the Duke program.
Still, Blumenthal waxes optimistic. After all, Tucker and three other current members of the commission are among those who ruled last year that Duke should present the new incentive program.
“They seem to recognize there is value to distributed batteries being added to the grid,” Blumenthal said. “The fact that [the proposal] is cost-effective is key because the idea is, the more of it you do, the more savings there are.”
Two corrections were made on Dec. 10, 2025: This story originally misstated the number of times a year that Duke can tap a PowerPair participant’s battery; it is 30 to 36 times a year, not 18. The story also originally misstated the enrollment Duke expects for the nonresidential program; the utility expects 26 megawatts of batteries, not 26,000 customer participants.
President Donald Trump has made it his mission to banish offshore wind farms from America. He has derided wind energy as unreliable and expensive while freezing permitting and halting projects already under construction.
Yet a new report suggests that the president’s moves could be working against grid reliability in key parts of the country. Along the Northeast and mid-Atlantic regions, offshore wind can play a critical role in keeping the lights on year-round, especially through the winter, according to a study published this month by New York City–based consultancy Charles River Associates.
Trump’s attacks on offshore wind and other renewable sectors come amid dire challenges for the nation’s power system. The world’s wealthiest companies are building power-hungry data centers as grid infrastructure ages and households’ energy bills skyrocket. The White House itself has declared an “energy emergency,” which it’s using to push for more fossil-gas, coal, and nuclear power plants.
But offshore wind is well suited to “meeting the moment,” in part because gas plants are reliable in the summer but can buckle under winter weather, according to the study. Ocean winds in the Northeast are at their strongest and steadiest in winter months, making turbines there a way to boost the reliability of power grids connected to underperforming gas plants.
Oliver Stover, a coauthor of the study, called offshore wind farms a “near-term solution,” saying that turbines at sea and gas plants on land complement each other throughout the Northeast’s changing seasons: “They’re stronger together.”
Stover explained that if grid reliability is the goal, it makes sense for planned offshore wind farms to reach completion. Those projects will help regional grids burdened by extreme winter weather and data-center demands “buy time” as more infrastructure is built.
“Every megawatt is a good megawatt,” he said.
The periods in which offshore wind performs best also align with the time of increasing grid strain: winter mornings and evenings, when people tend to crank up the heat. While peak electricity demand has historically happened during the summer months, it is shifting to these winter moments in many parts of the country, largely due to the mass electrification of space-heating systems.
That means securing power generation during colder months must be, according to Stover, “a priority going forward.”
Stover and his colleagues aren’t the first to underscore the reliability benefits of offshore wind. Other analysts, along with grid operators, have warned that Trump’s efforts to squash certain projects that East Coast states were planning to rely on could raise blackout risks and power bills in the region.
Take Revolution Wind: Trump paused construction of the Rhode Island project in August due to “national security concerns” that a federal judge said were not rooted in “factual findings.” Having won an injunction in court, developer Ørsted eventually resumed construction one month later.
But during the pause and amid mounting uncertainty over the project’s fate, ISO New England — the region’s grid operator — released a statement saying that delaying delivery of power from Revolution Wind “will increase risks to reliability.”
Susan Muller, a senior energy analyst at the Union of Concerned Scientists, told Canary Media that if Revolution Wind were killed, the impact would be most acutely felt in winter months. That’s when the region’s limited supply of fossil gas is stretched even thinner, since the fuel is used for both building heating and power generation.
Losing Revolution Wind’s electricity entirely would have cost New England consumers about $500 million a year, according to Abe Silverman, a research scholar at Johns Hopkins University. His estimation was based on the value that the offshore project had secured in ISO New England’s forward capacity market as well as its potential to supplant costlier power plants used during grid emergencies, like snowstorms.
“We don’t need a bunch of fancy studies to tell us that these units are needed for reliability,” Silverman told Canary Media in September during Revolution Wind’s government-ordered pause.
In Virginia, the world’s data-center capital, America’s largest offshore wind farm is slated to start generating power in March 2026. Trump has not yet targeted the 2.6-gigawatt project, but if it doesn’t come online as planned, the mid-Atlantic grid region run by PJM Interconnection would be less reliable and have higher electricity costs, this month’s study says.
In a large swath of the Mid-Atlantic region, offshore wind has one of the highest “resource-adequacy” scores among energy types, according to the study. In other words, when it comes to lowering the probability of blackouts there, offshore wind outcompetes all other types of renewable energy — and is even on par with the most efficient gas-fired power plants.
But the sector is not without its issues, Stover emphasized. Even before Trump’s anti-wind policies made investors skittish and permits no longer guaranteed, construction costs had been ballooning for years, given supply chain issues and inflation.
Offshore wind farms are also, by nature, megaprojects that come with inherent logistical hurdles. Just last month, New York’s Empire Wind lost the turbine-construction vessel it was banking on, due to a skirmish between two shipbuilding companies. Only a handful of boats in the world are capable of doing that kind of work.
The report’s conclusions stand in stark contrast to rhetoric coming from top officials implementing Trump’s war on offshore wind. The sector was just taking off in the U.S. when the president was inaugurated in January, with the first commercial-scale project coming online last year and five more arrays now under construction.
“Under this administration, there is not a future for offshore wind because it is too expensive and not reliable enough,” Doug Burgum, secretary of the Interior Department, told an audience in September at a fossil-gas industry conference in Italy.
Burgum’s statements mirror some of Trump’s favorite talking points that have long misled the public about the risks of wind power. In September, Trump told the United Nations General Assembly in a speech that “windmills are so pathetic and bad” because of their unreliability, falsely claiming that wind power is “the most expensive energy ever conceived.”
The grid does not automatically face problems when “the wind doesn’t blow,” as Trump falsely claimed at the United Nations. Grid operators routinely handle the intermittent nature of power generation from multiple sources — whether it be solar, gas, or wind turbines — through grid-management techniques and, increasingly, battery storage.
Trump is wrong about costs, too.
While offshore wind energy is currently expensive, nuclear energy — a sector the Trump administration aims to boost — is typically the most expensive type of power.
Globally, power generated from wind turbines in the ocean is comparable to other sectors such as geothermal and coal when it comes to cost-competitiveness. In fact, offshore wind has become more cost-competitive relative to other power types in recent years as the sector has matured in Europe and China, according to the most recent analysis by financial advisory firm Lazard.
But when temperatures plummet, offshore wind power could be a huge cost-saver for many U.S. residents. One analysis found that in New England, if 3.5 gigawatts’ worth of under-construction offshore wind farms had been online, households there could have saved $400 million on power bills last winter. In the coming months, cost savings and reliability will take center stage as Vineyard Wind, the region’s first large-scale offshore wind farm to break ground, feeds the grid for its first full winter season.
Two new battery projects on Virginia’s remote eastern peninsula could signal a growing trend in the clean-energy transition: midsize energy-storage units that are bigger than the home batteries typically paired with rooftop solar, but cheaper and quicker to build than massive utility-scale projects.
The 10-megawatt, four-hour batteries, one each in the tiny towns of Exmore and Tasley, represent this “missing middle,” said Chris Cucci, chief strategy officer for Climate First Bank, which provided $32 million in financing for the two units. Batteries are a critical technology in the shift to renewable energy because they can store wind and solar electrons and discharge them when the sun isn’t shining or breezes die down.
When it comes to energy storage, “we need volume, but we also need speed to market,” Cucci said. “The big projects do move the needle, but they can take a few years to come online.” And in rural Virginia, batteries paired with enormous solar arrays — which can span 100-plus acres — face increasing headwinds, in part over the concern that they’re displacing farmland.
The Exmore and Tasley systems, by contrast, took about a year to permit, broke ground in April, and came online this fall, Cucci said. Sited at two substations 10 miles apart, the batteries occupy about 1 acre each.
Beyond being relatively simple to get up and running, the systems could help ease energy burdens on customers of A&N Electric Cooperative, the nonprofit utility that owns the substations where the batteries are sited, said Harold Patterson, CEO of project developer Patterson Enterprises.
Wait times to link to the larger regional grid, operated by PJM Interconnection, are up to two years. So for now, the batteries will draw power only from the electric co-op, Patterson said. Once they connect to PJM, the batteries will charge when system-wide electricity consumption is down and spot prices are low. Then, the batteries’ owner, Doxa Development, will sell power back when demand is at its peak, creating revenue that will help lower bills for co-op consumers.
“That’s the final step to try to drive down power prices” for residents of Virginia’s Eastern Shore, Patterson said. “Get it online and increase supply in the wholesale marketplace.”
Though the batteries aren’t paired with a specific solar project, they are likely to lap up excess solar electrons on the PJM grid. And since they’ll be discharged during hours of heavy demand, they could help avert the revving up of gas-fired “peaker plants.”
“Peaker plants are smaller power plants that are in closer proximity to the populations they serve, and [they] are traditionally very dirty,” Cucci said. “They’re also economically inefficient to run. Battery storage is cleaner, more efficient, and easier to deploy.”
Gas peaker plants are wasteful partly because of all the energy required to drill and transport the fuel that fires them, said Nate Benforado, senior attorney at the Southern Environmental Law Center, a nonprofit legal advocacy group.
“Then you get [the fuel] to your power plant, and you have to burn it,” Benforado said. “And guess what? You only capture a relatively small portion of the potential energy in those carbon molecules.”
Single-cycle peaker plants, the most common type, can go from zero to full power in minutes, much like a jet engine. Their efficiency ranges between 33% and 43%.
“Burning fossil fuels is not an efficient way to generate energy,” Benforado said.
“Leaning into batteries is the way we have to go. They’re efficient on the power side but also on the price side.”
Texas proves the financial case for batteries. The state has its own transmission grid, no monopoly utilities, and no state policies to speed the clean-energy transition. Yet it’s gone from zero to some 12 gigawatts of batteries in five years.
In Virginia, A&N Electric Cooperative isn’t the only nonprofit utility investing in energy storage: The municipal utility in the city of Danville, on the North Carolina border, announced earlier this year that it’s building a second battery project of 11 megawatts. Its first system, a 10.5-megawatt battery, which went online in 2022, is on track to save customers $40 million over two decades, according to Cardinal News.
“You look at Texas, where developers are trying to make money on projects,” said Benforado. “And now you see co-ops and municipalities saying, ‘This can save our customers significant amounts of money.’ That, to me, is very telling about the economics of batteries.”
Those economics are even rosier in light of the federal tax credits available for grid batteries, among the few green incentives to survive the budget bill that congressional Republicans passed this summer. Those credits start phasing down in 2033.
While nonprofit utilities in Virginia aren’t impacted by a 2020 state law that requires investor-owned Dominion Energy and Appalachian Power Co. to decarbonize by 2045 and 2050, respectively, they help show what’s possible for the state.
“We need to build things,” Benforado said, especially in the face of skyrocketing demand from data centers. “The question is, are we going to build clean resources or not? We need to build batteries, not gas.”
Climate First Bank and Patterson Enterprises, for their part, have more midsize energy-storage systems in the works. In fact, in December they expect to break ground on another 10-megawatt project — in Wattsville, 20 miles up the road from Tasley.
“We are talking to a lot of developers on projects ranging from 2 megawatts to 10 or 15 megawatts,” Cucci said. “A lot of those players are saying, ‘Let’s shift a little more heavily into storage.’”
The data-center boom is pushing electricity costs to the breaking point for PJM Interconnection — the country’s biggest grid operator, serving more than 65 million people from the mid-Atlantic coast to Illinois — and that’s fueling a popular backlash.
Democratic gubernatorial candidates pledging to combat rising utility bills just won landslide victories in New Jersey and Virginia, two states bearing much of the brunt of data-center-driven cost increases. Congress members along with state governors and lawmakers are demanding that PJM take action.
PJM is poised to make a key decision this week on a fast-track process to get data centers online quickly while mitigating the impact of the facilities, which can use as much power as small cities. But a conflict has emerged over how far the grid operator can go. It boils down to this: Can PJM force data centers to stop using electricity at moments when demand for power peaks?
Data-center trade groups say no. But a growing number of politicians and environmental and consumer advocates say that requiring data centers to be the first to get disconnected from power during grid emergencies is the only surefire way to protect customers.
Last week, a bipartisan coalition of state legislators representing many of the 13 states served by PJM submitted its Protecting Ratepayers Proposal, which argues for data centers to be allowed to connect to PJM’s grid with the stipulation that they will be “‘interrupted’ during grid emergencies until they bring their own new supply.”
“We have a responsibility to ensure that technological growth doesn’t push vulnerable residents into financial hardship or enable a massive transfer of wealth from ratepayers to data centers,” said Maryland state Sen. Katie Fry Hester, a Democrat and organizer of the coalition, in a press release introducing the proposal.
“This proposal is about fairness and responsibility,” added Illinois state Sen. Rachel Ventura, also a Democrat. “We’re making sure data centers carry the cost of their own energy demands instead of passing it on to the public.”
That’s a salient concern, because the peak power needs of data centers are what’s driving electricity costs through the roof in PJM territory.
The grid operator must secure enough capacity from power plants and other resources to serve its peak loads. The prices of securing that capacity have skyrocketed in the past two years, from $2.2 billion in 2023 to $14.7 billion in 2024 and to $16.1 billion in PJM’s latest capacity auction this summer.
Growing demand forecasts of yet-to-be-built data centers are the primary culprit for these price spikes, and constitute the “core reliability issue facing PJM markets at present,” according to an August report from Monitoring Analytics, the company tasked with tracking PJM’s markets. “There is still time to address the issue but failure to do so will result in very high costs for other PJM customers,” the report warns.
Utility bills are rising across much of the U.S. due to a combination of factors, including volatile fossil-gas prices and the expense of repairing and expanding power grids. Data-center growth is not directly increasing costs in most regions yet, but in PJM, utility customers’ bills already reflect the capacity cost increases tied to serving future data centers.
Groups including consumer advocates in Maryland and the Natural Resources Defense Council agree that requiring new data centers to get cut off first during grid emergencies is a vital backstop to the suite of interventions PJM is considering for its fast-track process.
“We’re proposing to allow data centers to join PJM’s grid as fast as they want, but not guarantee them firm service, so they’ll be given interruptible service until they bring their own capacity,” Claire Lang-Ree, clean-energy advocate at the Natural Resources Defense Council and coauthor of the environmental group’s proposal, explained during an Oct. 22 webinar. “We think that’ll solve both the cost and reliability problem, because by removing all these large loads out of the capacity market until they bring their own supply, … capacity prices might go back down to historic levels.”
PJM’s Members Committee is expected to vote Wednesday on a final advisory recommendation to send to the grid operator’s board of managers. PJM has said it intends to file a proposal in December with the Federal Energy Regulatory Commission, in hopes of gaining approval to institute changes in 2026.
Data-center companies and utilities are not happy about mandatory power cutoffs for new computing facilities, however — and their arguments have so far carried the day at PJM.
In August, PJM issued a “conceptual proposal” that included a “non-capacity-backed load” (NCBL) structure. The approach would force loads of 50 megawatts or larger to curtail power use to forestall grid emergencies as a precondition to interconnection.
That proposal was lambasted by the Data Center Coalition, a trade group that includes Google, Microsoft, Meta, Amazon, and dozens of other companies that own, operate, or lease data-center capacity. In comments to PJM, the coalition warned that by imposing NCBL status on data centers, the grid operator “risks exceeding its jurisdictional authority” over customer interconnection and interruptibility status, which are generally managed by utilities regulated at the state level.
“PJM has not provided a defensible rationale for creating this new class of service, and on its face the proposal is unduly discriminatory,” the coalition wrote.
PJM responded by pulling the NCBL concept from its next round of proposals, instead offering new data centers a voluntary method to commit to curtailing their peak power use through tweaks to a structure called “price-responsive demand,” or PRD.
As PJM explained in an October update, “With these changes, PRD becomes similar to voluntary NCBL,” since data centers that opt in would be exempt from paying for capacity but be obligated to “reduce demand during stressed system conditions.”
The big question is if data-center developers will choose to act at the scale required to “move the needle,” as analytics firm ClearView Energy Partners put it in a November research note. The authors wrote that, according to their observations in recent PJM meetings, “it’s far from clear whether new large load[s] would take service via this voluntary program.”
Consumer advocates aren’t happy with the data-center industry’s resistance to mandatory controls. Clara Summers, campaign manager for the Citizens Utility Board, an Illinois-based consumer-advocacy group, told Canary Media that the Data Center Coalition’s positions “are generally disappointing, given how some individual members of the DCC have shown a willingness to hammer out decent solutions that actually take responsibility for their own costs.”
Summers is referring to a handful of efforts by tech giants and data-center developers to use their own capacity resources to reduce their grid impacts. One such rare example is an agreement Google reached in August with PJM utility Indiana Michigan Power that commits the tech giant to bringing additional new capacity online and lowering power use during times of peak demand to alleviate the impacts of expanding a massive data center in Fort Wayne, Indiana.
Most of the groups submitting proposals to PJM agree that its new rules should enable data centers to fast-track development by paying for generation and other capacity resources to serve their own needs. Stakeholders also agree that data centers that can use less power during times of peak demand should be rewarded for the relief that would provide to PJM’s system.
The Data Center Coalition has also won backing from the governors of Maryland, New Jersey, Pennsylvania, and Virginia, four states in PJM territory courting data centers for economic development. Those governors joined the coalition in submitting a proposal for the fast-track process that would task state regulators with expediting interconnection for data centers that can add enough new generation capacity to the grid to cover their energy demand at the time they are connected.
But groups arguing for mandatory restrictions say these alternatives may not take effect quickly enough to prevent data-center growth from outpacing the capacity of PJM’s grid.
PJM’s notoriously backlogged interconnection queue is impeding the addition of new power plants to the system. The grid operator’s efforts to fast-track new generation resources have yielded only a handful of projects expected to come online before 2030.
PJM is still in the early stages of developing options to add capacity to existing generators, such as pairing batteries with solar and wind farms. And proposals that let data-center developers tap into the flexibility of virtual power plants remain a work in progress.
Meanwhile, PJM’s grid is only just beginning to feel the pressures of data-center expansion. The latest forecasts of large-load growth across PJM territory show 32 gigawatts of additional demand by 2028 and about 60 gigawatts by 2030, or a 37% increase from PJM’s peak load today, according to the Maryland Office of People’s Counsel, the state’s consumer advocate.
The sheer scale of proposed data-center construction beggars belief. To meet that projected demand, “by 2028, [developers] would have to be investing about $1 trillion within PJM in the next three to four years,” David Lapp, who leads the Maryland office, said during a press conference last month. “That’s an insane amount of money.”
Many groups are arguing to keep price caps on PJM’s capacity auction in place to mitigate the pass-through costs of rising data-center demand. They’re also pushing for PJM to order utilities to more stringently clear their load forecasts of speculative or redundant data-center applications, which experts agree are inflating expectations of how much load utilities and grid operators will have to serve.
But utilities, power-plant owners, data-center developers, and the tech giants spurring the AI boom have little reason to constrain these outsized growth plans, or to concede to restrictions on their peak power use, Lapp said. These are “some of the most powerful corporations in the world, all increasing their bottom line on the backs of existing customers,” he said.
As the 20th century ended, the National Academy of Engineering chose the top 20 engineering achievements of the past 100 years. At the top of the list was electrification, which beat out space travel, automobiles, computers, and the internet.
The 21st century may also be defined by electricity. The future unfolding before our eyes — from advances in artificial intelligence (AI) and automation to the electrification of transportation — depends on vast and growing quantities of electricity. The International Energy Agency (IEA) expects global electricity consumption to grow by nearly 4% annually through 2027 and declared the world is entering a “new Age of Electricity.”
With the world increasingly dependent on electricity, grid resilience is essential. Unfortunately, threats to grid resilience are quickly growing in both volume and seriousness. Extreme weather events, for instance, are now more frequent and powerful. The U.S. experienced an average of 23 natural disasters causing at least $1 billion in damages each year between 2020 and 2024, compared with just nine per year over the prior three decades.
Other challenges to a resilient grid include the influx of distributed energy resources (DER), such as rooftop solar, energy storage, and electric vehicle (EV) charging, which can create two-way power flows, overload local feeders, and cause voltage fluctuations that strain grids. As the volume of DERs has spiked, so too has the threat from cybercriminals, who take advantage of the increased attack surface that so many grid-connected assets provide. The number of cyberattacks on U.S. utilities increased by 70% from 2024 to 2023.
The avalanche of threats to the grid was enough for the North American Electric Reliability Corporation President Jim Robb to warn of a “five-alarm-fire” for grid reliability. And when the grid is not resilient to growing threats, there are real-world consequences.
Between 2000 and 2023, for example, 80% of all major power outages were due to weather — primarily extreme weather including severe winds and thunderstorms, winter storms, and hurricanes. A recent study published in the journal Nature Communications found that one-, three-, and 14-day power interruptions reduce GDP in the area impacted by $1.8 billion, $3.7 billion, and $15.2 billion, respectively.
Utilities understand the importance of a resilient grid and have long been focused on improving their System Average Interruption Duration Index (SAIDI) and System Average Interruption Frequency Index (SAIFI) scores. However, the existing tools and approaches to resilience planning and operations are inadequate to today’s challenges. Siloed outage management systems (OMS), supervisory control and data acquisition (SCADA) systems, and geographic information systems (GIS) combined with advanced metering infrastructure (AMI) data, static studies, and limited DER visibility result in fragmented, slow, and ultimately inadequate approaches to resilience.
A modern approach to grid resilience
The key paradigm shift that utilities need to make is to go from imprecise and reactive resilience strategies to proactive planning driven by full grid visibility and sophisticated data analysis. Software platforms with access to OMS, SCADA, GIS, and other utility data sources make that shift possible by providing a foundation for a comprehensive analysis, which is impossible to do when information is siloed.
With comprehensive data, software can perform three types of analysis that are essential to grid resilience in today’s complex environment:
The best software platforms don’t just identify risks and vulnerabilities. They also translate results from analysis into recommendations for improved resilience through infrastructure investments, operational changes, demand response, strategic DER deployment, and other measures.
Transmission and distribution system operators worldwide face an increasingly common resilience challenge. “We are seeing massive increases in load from the electrification of vehicles and heating and cooling systems, as well as from data centers, coupled with increased variability from renewable energy. This is creating a greater need for analytical and optimization software solutions,” said John Dirkman, vice president of product management at Resource Innovations, whose Grid360 software platform provides contingency, sensitivity, forecasting, and critical-load analysis to help utilities understand and address resilience challenges.
Recently, a large utility in Europe worked with Resource Innovations to model various loading scenarios, including what would happen if 10% or more EVs began charging in specific neighborhoods. The analysis identified where the added EVs would strain transformers and feeders and then produced a system heat map showing where the grid would be most vulnerable.
The software also provided recommendations to address potential problems. It analyzed the utility’s urban distribution system, where much of the infrastructure is underground and grid upgrades would be expensive and disruptive. The analysis suggested alternative actions to provide increased flexibility: demand response to reduce peak load, battery storage or vehicle-to-grid capabilities to provide localized system backup, and strategic placement of switches and power electronic devices to shift load between feeders.
While utilities around the world face different specific threats to grid resilience, the value that software can deliver in analyzing the grid for risks and suggesting tangible action is similar. For instance, in wildfire-prone regions, software allows utilities to systematically assess vulnerability by overlaying grid networks onto topographical and fire-potential maps.
This highlights the transmission and distribution lines that face the highest wildfire risk — in places like California, that is often in difficult-to-access canyon areas. Contingency analysis provides valuable intelligence, such as alternative routes if a line goes down during a fire and how much load those backup options can serve. Analysis can also suggest where backup generation or storage is most needed.
One example of software that does scenario planning by integrating data from multiple utility systems to model the grid under stressed conditions is Resource Innovations’ Grid360 Grid Impact Assessment System (GIAS). The web-based platform allows utilities to simulate everything from wildfire impacts to DER integration challenges and cyberattacks. This provides system planners and operators with real-time visualization and forecasting tools to prevent predicted problems with voltage, loading, and power quality before they occur. Grid360 GIAS also integrates with Resource Innovations’ iEnergy platform for interconnection, demand-side management, and demand response, allowing utilities to coordinate both infrastructure investments and customer-side resources to strengthen resilience.
“Our software allows the utility to model the grid and find ways to provide power under any scenario,” Dirkman said. “That kind of planning can be done either on a very specific location basis or network-wide.”
“Our software allows the utility to model the grid and find ways to provide power under any scenario. That kind of planning can be done either on a very specific location basis or network-wide.”
John Dirkman, Vice President of Product Management at Resource Innovations
There is little chance that threats to grid resilience will diminish in the future, and the consequences of inadequate resilience can be measured in billions of dollars and growing risks to public safety. It is not a time to rely on reactive approaches. Software platforms that analyze unique vulnerabilities and recommend solutions give utilities the tools they need to act proactively and ensure the grid remains reliable as the world enters its new age of electricity.
Surging power demand from new data centers is reaching unprecedented — and potentially unrealizable — heights.
Over the next five years, U.S. utilities expect to see new electricity demand equal to 15 times New York City’s peak load, the majority of which will come from data centers.
So finds a report released Tuesday by Grid Strategies tracking the growth in power demand for data centers being built and planned to feed tech giants’ artificial intelligence ambitions. The consultancy’s tally of utility load forecasts indicates that peak grid demand will boom to 166 gigawatts by 2030, a sixfold increase from what was forecast three years ago.
“These are just phenomenal numbers for an industry that was built over the past couple of decades to handle much lower load growth,” said John Wilson, Grid Strategies’ vice president and the report’s lead author.
Data centers make up roughly 90 gigawatts of that forecasted load growth, a reflection of the hundreds of billions of dollars that tech giants are pouring into AI, as well as smaller but still substantial investments in crypto-mining operations, enterprise cloud computing, telecommunications, and other IT services.
Back in late 2023, Grid Strategies offered an early warning about how data centers were causing power demand to spike. It has also cautioned that outsize plans for growth in key U.S. data center hot spots are threatening to exceed the physical capacity of power plants and power grids. These factors could result in higher costs for consumers and more carbon emissions as utilities plan to ramp up fossil-fuel use to serve new demand.
But Grid Strategies and others have also counseled that utilities might be exaggerating things.
For one, there’s lots of double-counting going on; data center developers often pitch the same project in multiple utility jurisdictions while searching for the best deal. For another, the gold-rush quality of the data center boom is leading developers to make speculative proposals for projects that may never materialize.
For its new report, Grid Strategies compared utility forecasts with alternative methods of projecting data center load growth, such as industry analysis of technological bottlenecks, and found that utilities may be overstating data center demand by as much as 40%.
That discrepancy indicates how utility forecasts need to better reflect underlying uncertainties, Wilson said. This is particularly important for the rising number of data centers being planned that will use a gigawatt or more of power — the equivalent of a small city’s total power demand.
“The fact that these facilities are city-sized is a huge deal,” Wilson said. “That has huge implications if these facilities get canceled, or they get built and don’t have long service lives.”
Utilities are using their sky-high forecasts to justify massive investments in power plants and grid infrastructure around the United States.
Those forecasts, in turn, have already driven up utility bills in some regions, including those for many of the more than 67 million people served by PJM Interconnection, the country’s biggest energy market. For PJM, future data center forecasts have driven capacity costs — the prices paid to power plants and other grid resources to meet peak grid demand — from $2.2 billion in 2023 to $14.7 billion in 2024 and to $16.1 billion in this summer’s capacity auction.
PJM customers in heavily impacted states like New Jersey are taking notice. Popular anger at rising bills helped propel Democratic gubernatorial candidates who pledged to combat increasing power costs to outsize wins in New Jersey and Virginia elections earlier this month.
Many utilities aim to meet this surging demand by building new fossil-gas-fired power plants, which could not only increase costs for customers but also slow down the transition to clean energy. Across much of the Southeast and the Midwest, in particular, utilities aim to build gigawatts’ worth of these power plants, which emit carbon dioxide as well as toxic air pollution.
In Virginia, home of the world’s largest data center hub, Dominion Energy is proposing gigawatts of new gas-fired power that, critics warn, could make it impossible for the utility to meet a state-mandated phaseout of fossil fuel use by 2045. The utility argues that the plants are needed to maintain reliability in the face of data center growth.
Meanwhile, in Georgia, major utility Georgia Power is seeking regulator permission to build gigawatts of gas-fired power capacity to meet load forecasts swollen by proposed data centers. Opponents fear that the plants will balloon already fast-rising utility bills, and this month voters overwhelmingly elected to the state’s Public Service Commission two Democratic challengers who ran on a platform of constraining unchecked utility spending.
Elsewhere, state lawmakers, regulators, and data center developers are seeking ways to accommodate growth without overwhelming the grid and utility customers.
In Texas, the country’s second-hottest data center market outside of Virginia, “large load” forecasts within the territory served by the Electric Reliability Council of Texas (ERCOT) have nearly quadrupled over the past year, representing a potential doubling of its peak demand. The state legislature passed a law this spring that requires new data centers to disconnect at moments of peak grid stress, although the rules for how that will happen are still being worked out by ERCOT and state regulators.
Other states are also passing laws and instituting regulations aimed at forcing data center developers to bear the cost of new power plants and grid infrastructure. And some data center companies are promising to shift when they use power in order to relieve peak grid strains that drive much of the costs that utilities face. PJM, for its part, is considering new rules aimed at requiring new data centers to reduce their impact on the region’s capacity costs, although consumer and environmental advocates say the grid operator’s proposed plans don’t go far enough.
The Grid Strategies report also highlights that U.S. utilities and grid operators haven’t yet committed to expanding the transmission grid at the scale needed to support the growing electrification of vehicles, buildings, and industries — however the data center demand plays out. “Even conservative growth trajectories outpace recent years and would require substantial grid expansion to accommodate,” it notes.
Ultimately, Wilson suggested that utilities, lawmakers, and regulators will need to make sure the cost of meeting whatever demand does materialize is not shifted to everyday customers.
“We’ve got a gigantic amount of additional load over the next five years to manage from a supply-chain, planning, and construction standpoint,” he said. “These are questions that regulators and intervenors should be asking, and not just trusting the utilities, who say, ‘This is the way we’ve always done it.’”
Due north of Chattanooga, a power line runs through a wooded tract called Sale Creek before it dead-ends at the Tennessee River. On Oct. 8, this line lost power. But the lights stayed on for nearly 400 customers because Sale Creek has a new tool to neutralize outages.
Chattanooga’s municipal utility, EPB, had installed a Tesla Megapack battery system on this lonely stretch of the distribution grid back in June. If anything knocked out the line, residents would have 2.5 megawatts/10 megawatt-hours of storage capacity at their disposal while crews fixed the problem.
In this case, utility workers unexpectedly needed to de-energize the line to finish making repairs. EPB was able to switch the neighborhood over to battery power for about half an hour until the job was done. Without the battery, EPB would have had to tell its customers it was cutting off their power on purpose.
“This was the first time we used it in an outage situation,” said Ryan Keel, president of the energy and communications business unit at EPB. “In the future, it’ll be even more unplanned. It’ll be a response to a tree falling through the line or a car hitting a pole or something.”
EPB, which serves some 500,000 people across 600 square miles, plans to roll out more targeted, resilience-oriented batteries to other outage-prone stretches of its grid. The nonprofit public power company currently has a 45-megawatt fleet of batteries, almost all of which were built this year. Besides keeping the lights on, they save money for the whole customer base by lowering the utility’s peak electricity consumption.
The United States is racing toward yet another record year of grid battery construction, as power companies tap lithium-ion batteries to store solar power, improve grid reliability, and free up capacity for new data centers. Most of these batteries are getting installed in California and Texas, where they’ve pushed down wholesale prices and banished heat wave–induced power shortages. Utilities elsewhere, though, too often bide their time in exhaustive studies of the technology, which is new by their standards, despite its mass deployment in some regions.
But batteries are starting to catch on in Tennessee: The Tennessee Valley Authority, the federal entity that generates electricity for EPB and scores of other local power companies, just committed to build 1.5 gigawatts of grid batteries across its territory by the close of 2029, its largest battery deployment by far. The TVA board approved this in its November meeting, setting the stage for the utility to solicit competitive bids from battery developers, spokesperson Scott Fiedler told Canary Media.
And although Chattanooga’s battery buildout is far smaller than what’s happening farther west, or even the installations planned by TVA, it shows how a responsive local utility can adopt new clean-energy technology to make life a little better for its customers. It doesn’t take a massive R&D budget or piles of cash from Wall Street shareholders — just a willingness to embrace a readily available technology.
EPB had explored batteries for years. It researched them with the Department of Energy and Oak Ridge National Laboratory, located 100 miles northeast of Chattanooga. But EPB moved beyond research and installed a solar-and-battery microgrid at the Chattanooga Airport, learning how to work with the technology in practice.
Building on that experience, EPB leaders took a new look at batteries after Winter Storm Elliott rocked the region just before Christmas 2022, leaving TVA short on supply as households cranked their electric heating. For the first time since its founding in 1933, the TVA had to cut power to its customers in order to avoid damaging the grid infrastructure. So it told local power companies that they had to reduce demand by a certain amount.
“That event shaped our strategy,” Keel said. “We want to deploy a large amount [of batteries], because it gives us some local insulation from what may be happening on the TVA system that could impact our customers.”
Homes in TVA’s territory use a lot of electric heating and cooling, which drives grid peaks in both winter and summer. Typical hot summer and cold winter peaks for EPB reach 1,200 megawatts of demand, Keel said, but the utility set a demand record above 1,300 megawatts this January.
That means the current battery fleet meets just a small percentage of the total peak demand — enough to help on the margins, but pretty limited in its impact. Keel said his strategy is to raise that capacity to around 150 megawatts.
“Our hope is that if TVA calls for a 10% required reduction of our load, we can achieve that completely with the battery systems that we’ve put in, and we don’t need to do any unplanned outages to customers at all, like we had to” during Winter Storm Elliott, Keel said.
That battery strategy is akin to an insurance policy, responding to the concerning frequency of polar vortices and extreme heat in recent years. But the batteries don’t just sit around waiting for record cold snaps or heat waves. When the batteries aren’t acting as local backup, EPB puts them to work to save money for all customers.
When EPB buys power from TVA, it pays a demand charge for the hour of highest consumption each month. By discharging the batteries when it looks like a peak hour is approaching, EPB can shave its monthly charge. That lowers the rates it pays to TVA, which puts downward pressure on utility bills for Chattanooga residents.
“We make our decisions based on community benefit,” said J. Ed. Marston, EPB’s vice president for strategic communication. “The more we can keep our costs down operationally, the more we can avoid having to do electric rate increases that impact our customers.”
This dynamic parallels the way Vermont utility Green Mountain Power pays for a program that helps customers install home batteries: The utility dispatches all the small-scale batteries to reduce its peak-demand charges to the New England grid operator.
EPB expects to get payback on its battery installations within five years from the reliability and peak-demand uses. The utility has elected not to run the batteries on a daily basis, because the wear and tear that frequent cycling puts on batteries offsets the benefit of short-term savings on energy charges. (TVA territory doesn’t have wholesale markets that let batteries bid in for various services to make money.)
EPB’s battery buildout puts it ahead of many bigger peers, in both absolute and relative terms.
It’s part of a pattern of the municipal utility embracing new technology to help its residents.
Perhaps most strikingly, the nonprofit installed fiber internet in city homes in 2009, before for-profit telecom providers were widely offering it. EPB became the first company to sell gig-speed internet to an entire community network, Keel said. (Current monthly rate for 1-gig Wi-Fi: an envy-inducing $67.99.)
That fiber also improves the efficiency of the electric grid: EPB piggybacked on the fiber to upgrade its grid network to advanced metering infrastructure, which sends real-time information to the utility and allows it to respond instantly to issues. EPB won accolades for the number of “smart grid” automated devices on its high-voltage distribution system per mile or per customer, Keel said.
“EPB has been incredibly impressive and forward-thinking and on the leading edge — sometimes maybe even on the bleeding edge — of technology innovation, all in the spirit of working for the benefit of their customers,” said Matt Brown, regional vice president for the Tennessee Valley at Silicon Ranch, the major solar developer based in Nashville.
Silicon Ranch is working with EPB on a different kind of money-saving clean-energy project. A large-scale solar project in West Tennessee will produce 33 megawatts for EPB as part of TVA’s Generation Flexibility program, which lets local power companies generate up to 5% of their annual demand. The project is slated to be operating by mid-2028.
That solar development will be located outside EPB’s territory, where there’s more land available. So it won’t be able to help with local reliability in Chattanooga, the way that the community batteries do. But it will generate power at cheaper rates than those of TVA, which itself has cheaper rates than most U.S. utilities, meaning that EPB can pass those savings to its customers.
“Prices are going up on everything from food to energy to housing. This provides them comfort to be able to have some rate stability and flexibility,” Brown said.
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