Reliability risk across North America is rising over the next decade as electricity demand growth, driven largely by new data centers, outpaces the pace of new generation, transmission and fuel infrastructure needed to support it, the North American Electric Reliability Corporation (NERC) said Thursday in its 2025 Long-Term Reliability Assessment.

NERC said summer peak demand is forecast to grow by 224 gigawatts (GW) over the next 10 years, a more than 69% increase over the demand forecast in last year’s assessment. Winter peak demand is projected to rise even faster, up 246 GW over the same period, as electricity use patterns evolve and more end uses shift toward electric heating and other winter-peaking loads.

“This assessment is not a prediction of failure but an early warning on the trajectory of risk,” John Moura, NERC’s director of Reliability Assessment and Performance Analysis, said during a media briefing Thursday. “The path forward is still manageable but only if planned resources come online and on time.”

NERC’s long-term assessment is built from a mid-2025 “snapshot in time” based on utility and market projections, and it is intended to flag areas where resource adequacy could tighten under the current buildout trajectory. In the briefing, Moura emphasized that the biggest issue is not a lack of awareness, but the speed of change.

“Reliability risk is increasing, and really not because we lack awareness, but that the system is changing faster than the infrastructure need to support it,” Moura said.

Mark Olson, NERC’s manager of Reliability Assessments, said the report’s risk map reflects the highest risk category each assessment area reaches over the next five years, using reserve margin targets and probabilistic analysis to evaluate the likelihood of unserved energy and load loss. Olson said more areas show elevated or high risk as demand projections rise and resource plans become more uncertain.

The report argues that uncertainty is now a structural feature of resource planning, and that timing has become as important as megawatts. NERC said projected retirements remain high, with 105 GW of seasonal peak capacity planned to retire over the next decade, although that total is down 10 GW from the prior assessment.

At the same time, the composition of planned additions is shifting quickly. NERC said battery storage projects have grown to match solar projections, and that natural gas additions represent about 15% of projected capacity additions, followed by wind and hybrid resources at 8% each.

During the call with journalists Thursday, Olson described a key seasonal challenge that planning models are now surfacing more clearly: resources in the development pipeline may show strong capability for summer peaks, but a very different contribution in winter.

“When we look at what their winter capability is, we can see this shortfall emerging where a lot of resource development is going to be needed in order to meet year-round peak demand and pay close attention to those winter demands,” Olson said.

NERC also pointed to lagging transmission development as a constraint on both reliability and resource delivery. The assessment notes that projected transmission development is rising compared with last year, but that miles of projects under construction have not increased substantially yet, and that delays tied to siting, permitting and other process hurdles remain common. Olson said interregional transmission projects are especially important during wide-area weather events because they can support transfers between neighbors.

Moura said the grid’s changing mix is altering what “stress” looks like, and why planning needs to move beyond traditional reserve margin thinking.

“We must move beyond margin only thinking to thinking about probabilistic and energy risk analysis,” he said.

In the briefing, Moura also pointed to system performance concerns that are not captured by an energy-only risk map, including stability challenges during periods of very high inverter-based resource output. He said the industry is paying closer attention to essential reliability services such as inertia, voltage support and frequency response.

“We’ve seen examples of that in the international space, including the recent Iberian Peninsula outage that underscored the need to manage system performance during periods of high inverter-based resource output,” he said.

The assessment’s headline demand story is closely tied to data centers. Olson said new data centers are the main driver of load growth in many areas, though large industrial loads and electrification also contribute.

During the briefing, Moura said flexibility from data centers could help them interconnect faster and reduce the need for near-term system upgrades if their peak contribution can be managed.

“If data centers can offload their demand usage to their backup centers or move load to different data centers … that flexibility, if that can happen and they are committed to not being there on during peak conditions, well, then they can be interconnected a little quicker,” Moura said.

NERC’s recommendations focus on speeding infrastructure development and improving coordination. The organization urged streamlining siting and permitting for generation, transmission and natural gas infrastructure, managing generator deactivations carefully, expanding adequacy assessments that incorporate energy limitations, and improving electric-natural gas coordination as reliance on gas-fired generation increases.

The bottom line, Moura said, is that the trajectory is moving in the wrong direction, but there is still time to bend it.

“The question is no longer whether the change is coming,” he said. “It’s whether the infrastructure and coordination can keep pace.”

Winter Storm Fern has passed, but roughly half a million Americans were still without power or heat on Tuesday, and temperatures were forecast to fall well below freezing in areas where the massive ice storm did its worst damage.

The U.S. Department of Energy (DOE) issued new emergency orders on Monday aimed at keeping power available as extended cold from Winter Storm Fern drives up demand and stresses fuel and generation availability in parts of the U.S.

One order authorized NYISO to run all generating units in the grid operator’s region and operate them up to maximum output levels, even if doing so conflicts with air quality or other permit limits, or if fuel shortages emerge during the emergency period. The order took effect Jan. 26 and runs through Feb. 2.

DOE issued two separate orders focused on behind-the-meter backup generation at large-load sites, authorizing both PJM Interconnection and Duke Energy Carolinas/Duke Energy Progress to direct certain backup resources at data centers and other large customers to operate as a last resort before an Energy Emergency Alert level 3 is declared, or during an EEA 3. The PJM order expires at 11:59 p.m. EST Jan. 31, and the Duke order expires at 11:59 p.m. EST Jan. 30.

Another order covers Duke Energy’s balancing areas on the central-station side, authorizing generating units in the Duke region to operate up to maximum output levels, regardless of air quality or other permit limits. It became effective at 12:00 a.m. EST Jan. 27 and expires at 12:00 p.m. EST Jan. 30.

DOE is using Section 202(c) to widen the operating envelope in multiple regions, both by authorizing grid operators to push central-station units harder and by allowing system operators and utilities to lean on customer-owned backup assets when grid conditions deteriorate. 202(c) is a temporary emergency authority that can require changes to how the electricity system operates during qualifying emergency conditions.

DOE’s actions began Jan. 24 with orders to PJM and ERCOT. The PJM order authorized operation of generating units across PJM up to maximum output levels, “notwithstanding” permit limitations or fuel shortages during the emergency window, effective Jan. 25 through the end of the day on Jan. 31.

The ERCOT order authorized the Texas grid operator to direct backup generation resources at data centers and other large-load customers under the same “last resort before EEA 3 or during EEA 3” construct, expiring at the end of the day on Jan. 27.

About 130,000 customers had no electricity in the Nashville, Tennessee, area, according to poweroutage.com. About 140,000 remained without power in Mississippi, and nearly 100,000 more in icy Louisiana.

Stay with Factor This Power Engineering for updates.

U.S. Energy Secretary Chris Wright on Jan. 22 directed grid operators to be prepared to call on unused backup generation at data centers and other large facilities as Winter Storm Fern bears down on much of the country this weekend.

The storm is testing the electric system across multiple regions, with heavy snow, sleet and freezing rain spreading across the south-central U.S. and moving east through Sunday. As of Saturday morning, more than 95,000 power outages had been reported nationwide, including roughly 36,000 in Texas and about 10,000 in Virginia.

According to the U.S. Department of Energy, more than 35 GW of backup generation capacity remains idle nationwide. DOE said making those resources available, if needed, could help mitigate the risk of rotating outages during periods of extreme cold and high demand.

The draft emergency order, issued under Section 202(c) of the Federal Power Act, would apply to data centers and major industrial or commercial facilities with auxiliary, standby, directly connected or battery storage resources. The order would allow grid operators to call on those resources only after demand response options are exhausted and before a Reliability Coordinator declares an Energy Emergency Alert Level 3.

The action aligns with warnings raised in the North American Electric Reliability Corporation 2025 Winter Reliability Assessment, released in November. The assessment found elevated risk across much of North America of insufficient energy supplies during extreme operating conditions.

NERC urged Reliability Coordinators, Balancing Authorities and Transmission Operators in higher-risk regions to review seasonal operating plans and communication protocols for managing potential supply shortfalls. The assessment also emphasized advancing winterization measures and securing fuel supplies to ensure generation remains available during prolonged cold weather events.

“At this time, NERC is encouraged that industry has taken actions to prepare for what appears to be a very challenging winter storm system,” the organization said in a statement Jan. 22.

In a separate update issued Jan. 23, PJM Interconnection said it has issued precautionary alerts ahead of the winter storm and an extended period of extreme cold expected to affect much of its footprint, which spans 13 states and the District of Columbia. Forecasts call for single-digit temperatures across much of the RTO between Jan. 23 and Jan. 27, with subzero conditions possible in PJM’s Western Region.

PJM peak demand could exceed 130,000 MW for as many as seven consecutive days next week, a duration PJM said it has never experienced during winter operations. Depending on conditions, PJM could also set a new all-time winter peak load on Tuesday, Jan. 27.

PJM said it is taking additional precautions with generation and transmission owners, including issuing Cold Weather Alerts and expanding them to the full region through Jan. 27. The alerts prompt coordination with generators to ensure staffing levels are sufficient, units are fully winterized, and operational limitations are accurately communicated to the grid operator, including startup times and minimum and maximum run durations.

PJM said it is preparing for the possibility that the cold weather could extend into early February and emphasized the importance of fleet performance during sustained, high-load conditions.

As artificial intelligence and data centers reshape the energy landscape, power providers are racing to meet soaring electricity demand with speed, reliability and sustainability in mind.

At the Wednesday morning Keynote at POWERGEN 2026, hosted in San Antonio, Texas, industry leaders explored how the sector is rethinking resource planning, generation strategy and customer partnerships to keep pace.

The session was moderated by Richard Esposito, R&D Program Manager – Southern Company, and featured Gene Alessandrini, SVP of Energy and Location Strategy – CyrusOne; Simon Tusha, CEO – TECfusions; Jennifer Knott, Executive Director, Strategy Implementation – NextEra Energy; and Elaina Ball, Chief Strategy Officer – CPS Energy.

‘We’re not good communicators’

Tusha, whose company TECfusions designs, builds, and manages data centers, addressed the elephant in the room head on: the negative sentiments surrounding data centers stemming from environmental and price concerns, to name just a few.

“As an industry, we are really good engineers,” Tusha said. “We’re really good dealing with public officials. We’re not good communicators. There’s not a single social influencer in the room doing a Tiktok or some sort of little viral clip. You know, we’re getting our ass handed to us in the public messaging […] This is as much of a PR process is it is anything.”

At NextEra energy, being proactive is key, Knott argued. The company sees communities expressing some concerns about data centers that may be have been addressed years ago – while others have valid concerns that shouldn’t be ignored.

“As we go into into the communities, you get questions that are maybe based off of what was being done five years ago, and things have have changed significantly since then,” Knott said. “So I think being proactive and going into the community and saying, ‘here’s here’s the benefit, here’s the jobs we’re going to bring, here’s the the opportunities that this is going to create,’ while also acknowledging some of the constraints around putting a data center. What is the water consumption? Don’t sugarcoat the concerns, but address them head on.”

Alessandrini, whose employer CyrusOne also designs, builds, and operates data centers, noted that data centers are not a new, unheard-of phenomenon – they’re just coming online in a scale that most never anticipated, causing noise and confusion.

“I think the industry wanted to be a quiet industry,” Alessandrini said. “They just wanted to quietly put up data centers. Nobody knew they were there. They generally don’t make a lot of noise. But now that they’re scaling so large, they’re consuming a lot more energy, and because of that it’s putting more stress on the electrical grid, and because it’s putting more stress on electrical grid, that gets to […] the headline news, right?”

‘The rules are not yet written’

While many RTOs, ISOs, utilities, and regulators are attempting to address data center capacity concerns, we’re still essentially in the wild west portion of the data center boom: the rules and foundations just aren’t all there yet.

“One of the biggest challenges we’re seeing is the rules are not yet written, right?,” Knott said. “I think everybody’s trying to figure out, how do we bring these large loads on online? And so it’s really a partnership between developers, the ISOs, load serving entities, to figure out: how do we do this, how do we do it safely, how do we do it reliably?”

Tusha wasn’t too optimistic about the future regulatory landscape – arguing that regulators are responding to public pressure and would “screw it up.”

“The regulators that are doing this are they’re not responding to the science,” Tusha said. “They’re responding to the political winds that are blowing back and forth, ebbing and flowing.”

BEHIND THE METER?

“Generally, in today’s market, due to the constraints and challenges, the timeline for delivery for power is generally five to seven years,” Alessandrini said. “So with that, and us trying to plan the based on the market demands we have, we are now looking at alternatives.”

CyrusOne is taking a three-tiered approach to data center power development: co-location, co-development, and larger scale projects. Depending on scale, co-development can be take two years, co-location could take two to three years, and larger scale projects could take three to five years. The end result is a relatively consistent delivery portfolio with all three options blended together. Then, later down the line, the facilities still have the option to acquire a grid connection once things have settled down.

“In all honesty, the data center is not necessarily going to wait,” Alessandrini said. “They’re going to be constructive and collaborative, but they’re going to continue to go down this behind the meter generation solution.”

Facing lengthy interconnection queues, TECfusions has also gone all-in on behind-the-meter generation.

“Because interconnection agreements take so long, we’ve just said, ‘Okay, we’re going to be FERC 2222 compliant,'” Tusha said. “We’re going behind the meter and we’re just leaving it and just literally walking away.”

Speed to market

At CPS Energy, projected load growth and old, aging assets have forced the utility into action.

“We have some very new assets, and then we have some assets that have earned their AARP cards,” Ball said. “This is not about politics. This is about very old assets that that are at an end of life. So we are retiring conventional gas assets and converting some assets. And over the last three years we we’ve had a plan to add about 5,700 megawatts to our fleet by the end of 2030 – we’re about 82% there.”

Ball also discussed how the utility is addressing those shortfalls by making some thrifty investments in the gas space, acquiring assets for less than the cost of construction.

“We decided on the gas front to take a different strategy,” Ball said. “We are fortunate to operate into a very integrated, competitive, wholesale market. S we entered into several processes to acquire assets, and we’ve been successful in bringing on over 3,300 megawatts of natural gas assets well below the cost of construction that are operating assets now. It’s actually reduced our expected cost from over $5 billion in new build, and we’ve reduced that that capital outlay by $3 billion, so we’ve acquired these assets for just about a little more than $2 billion.“

One thing has become clear to CPS Energy over the past year or so: it’s all about speed over anything else.

“We have everything from behind the meter, in front of the meter, gas, fuel cell – you name it,” Ball said. “The conversation has changed here in the near term […] The conversation is all speed to market.”

With explosive load growth projected from data centers, manufacturing and electrification, grid operators are warning of looming capacity shortfalls. At the same time, generators are facing mounting pressure to adapt to evolving market structures, seasonal reliability risks, and shifting regulatory expectations.

At the Tuesday afternoon Keynote at POWERGEN 2026, hosted in San Antonio, Texas, energy executives shared how their regions are responding to these challenges: Implementing market reforms, rethinking capacity accreditation and rebalancing risk across market players, while also exploring what these changes mean for utilities and IPPs seeking to stay competitive and reliable in a grid under strain.

The session was moderated by Hari Gopalakrishnan, Manager, Market Strategy – Mitsubishi Power Americas and featured Keith Collins, Vice President of Commercial Operations – ERCOT; and Casey Cathey, Vice President, Engineering – Southwest Power Pool (SPP).

‘What is the alternative?’

The early aughts were a period of heavy gas development – but recent deployments, including a much bigger share of renewables, have put that growth to shame. However, as the modern resource mix begins to take shape, gaps and bottlenecks have begun to emerge.

In ERCOT, the shift toward solar in particular has created a unique problem: what we have typically thought of as the period of most stress has changed. Peak demand is still occurs around the late afternoon, but a significant amount of solar generation is operating during this period – including charging battery storage. Instead, the greatest period of need on the system in terms of system stress has shifted to later in the day – around eight or nine in the evening – resulting in higher prices.

In Collins’ eyes, this issue has opened up opportunities for new technologies to help allow the grid to adapt to this new reality, including synthetic inertia or gid-forming technologies. But another issue remains: winter.

“The challenge is during the winter months, and ultimately, the average storage duration in ERCOT is about one and a half hours,” Collins said. “And when you think of a cold winter spell, it can, can require not just a single peak during the day, but a double peak during the day. And the challenge there is having the storage capable of meeting a morning peak period as well as an evening peak period.”

New transmission will be an inevitable necessity to help ease some grid strain, Cathey argued.

“This is an investment – transmission is not cheap,” Cathey said. “But the question is, what is the alternative? We are maxed out on our transmission system, and we need to be able to build transmission to complement necessary supply. We, quite frankly, need both. We need generation and transmission to be able to support the future.”

‘We could have a problem’

ERCOT’s system peaks at 85 GW, but is staring down the barrel of over 230 GW of new demand. Unsurprisingly, most of that demand is coming from large load data centers.

“If we start connecting all the large loads, and you look at the growth of resources we have in our system, we could have a problem in the next few years,” Collins said.

As recently as seven years ago, SPP was excited to see 1.2% year over year load growth. Now, it’s seeing upwards of 5% year over year growth, which Cathey said he hasn’t seen in his whole career. The SPP system currently peaks at 56 GW, but at least 110 GW are waiting in the interconnection queue.

SPP has been undertaking a wholesale changing of its fuel mix – swapping out old coal plants and replacing them with wind and solar. But the hefty amount of new generation waiting to interconnect to replace aging generation has also caused delays.

“At one point in time, the [generator interconnection] process worked, but it was never designed for a wholesale fuel mix change and swapping out the entire supply of multi state region,” Cathey said.

At SPP, a new performance-based accreditation process will go into effect next cycle, which is meant to ensure generation shows up when it’s called on. But it’s difficult to accurately plan for the future without leaving gaps or overcompensating.

“We have 64 load responsible entities, utilities that meet these resource adequacy requirements,” Cathey said. “One of the challenges we’re seeing is the nature of the system is changing so fast, even if we set a planning reserve margin four years in advance, it’s hard to have a reliable number to give them for a particular resource.”

To help alleviate this, SPP recently filed what it calls a consolidated planning process with FERC which essentially adds the generation interconnection process into SPP’s regional transmission plan. Generators would have an upfront cost to connect under this process.

“There’s no games around, playing chicken with another developer, trying to withdraw from a queue and then seeing what the results are, seeing if you don’t induce certain electric or extra high voltage facilities, and being hit with hundreds of millions of dollars of cost,” Cathey said.

Short-term plans

Some technologies like geothermal and next-generation nuclear could help ease much of the strain on the grid. The problem, however, is that they’re just not mature enough yet. Collins hopes this will change in the next five to 10 years, but what about in the meantime?

Natural gas has been a no-brainer for getting generation online quickly, but with that supply chain facing backlogs, it could take years to get a turbine. Power producers could pay to take someone else’s spot in the turbine queue, but this isn’t sustainable for the industry as a whole.

So for the short term, we’re left with the relatively quick deployments of solar and storage – with solar taking around 24 months and storage taking between 12-18 months to come online. But recent policy shifts at the federal level have raised questions about this solution as well.

“Obviously, federal policy has changed in terms of tax incentives for new renewable resources, and we haven’t seen how that’s going to change the equation,” Collins said. “In the short run, there are phases that we’re likely to see changes, and part of that is a result of policy, part of that as a result of supply chain technologies. So I think over the next five to 10 years, we’re going to see a significant shift.”

“We’ve got to move though,” Cathey said. “I think that’s one problem that we’ve had as an energy industry: We spend a lot of time. I think we spent four years on a demand response policy. We can’t do that anymore.”

POWERGEN 2026 continues through Jan. 22 at the Henry B. Gonzalez Convention Center, with a week of executive dialogue, technical sessions and networking for the power generation community.