Reliability

The North American Electric Reliability Corp. on May 4, 2026, issued a rare Level 3 alert — the watchdog’s highest level — following instances of data centers unexpectedly dropping load or oscillating demand rapidly, creating reliability concerns. The alert includes seven actions grid entities “must implement to address immediate risks posed by computational loads,” NERC said.

Transmission planners and operators, system planners and balancing authorities are among the entities that must act. The required actions address the modeling, study, operation, protection and control of computational loads, including artificial intelligence training and cryptocurrency mining.

“The grid faces unprecedented challenges from a surge in large power consumers,” NERC said in a statement. Summer peak demand across the bulk power system is expected to rise 24% in the next 10 years, with data centers accounting for most of the increase, the organization said in its Long Term Reliability Assessment, published in January, 2026.

In the face of rising data center loads — and instances where they unexpectedly disconnected from the grid — NERC issued a Level 2 warning last year that elicited alarming responses from grid stakeholders, the reliability watchdog said.

“Entities generally did not have sufficient processes, procedures, or methods to address emerging computational loads,” NERC said in its Monday warning. The essential actions NERC calls for include the following:

• Transmission planners and planning coordinators should develop a detailed list of modeling data, settings, and parameters needed from computational loads and distribute this to transmission operators in their footprint. Transmission operators should reflect this information in their facility interconnection requirements.
• Transmission planners and planning coordinators should collect data from computational loads such as the expected minimum and maximum consumption in megawatts and the percentage of IT load vs. non-IT load (cooling, for instance), at various load levels.
• Planning coordinators should revise definitions that trigger a review of local area protections, stability limits and other reliability studies to account for computational loads.
• Transmission operators should establish a “commissioning process” for computational loads.
• Where possible, the commissioning process transmission operators develop should include testing facilities at full load and at no load, and, if possible, with at least a 10% change from nominal voltage.
• Transmission operators should install and utilize dynamic fault recording devices to understand computational load facility electrical performance during system disturbances.

Registered NERC entities must acknowledge receipt by May 11 and must respond by Aug. 3.

Level 3 alerts, which are rare, call for grid operators to take specific steps in response to an immediate issue. NERC last issued a Level 3 alert a year ago regarding possible grid disruptions related to inverter-based resources. Solar, wind and battery resources have been known to trip offline during grid disturbances. 

Grid instability issues caused by data centers "could become quite severe — to the the point of creating widespread blackouts," Ben Inskeep, program director for the Citizens Action Coalition, told Utility Dive in an email.

"It is critical that we have standards in place to protect all ratepayers from negative impacts to grid stability, reliability, and resiliency that are caused by data centers, especially given the rapid proliferation of these mega users across the country," Inskeep said.

NERC’s efforts to better align utility and data center operations may take longer than anticipated, Digital Power Optimization CEO and founder Andrew Webber told Utility Dive. The company builds and manages data centers.

“It will take years of coordinated effort in the drafting of new regulations, understanding limitations and opportunities related to physical equipment, understanding limitations and opportunities related to software and control systems, re-prioritizing various loads all throughout society, etc.,” Webber said in an email.

He pointed to recent comments by Laura Swett, chair of the Federal Energy Regulatory Commission, about a lack of communication between data centers and energy regulators.

“Given the absolutely critical need [for data center developers] to source power for their developments, I found it quite interesting that FERC isn’t seeing more direct engagement from the data center industry,” Webber said. “I think it exemplifies the challenges NERC is also going to face in getting genuine buy-in and wholehearted acceptance by the data center industry as it pertains to grid reliability.”

“New evaluation paradigms will need to be created and worked through in partnership with the data center industry,” he said.

The PJM Interconnection on May 6, 2026, proposed three broad frameworks for reforming its markets to help ensure its 13-state region has adequate power supplies to meet growing demand.

The options are: stabilizing PJM’s existing capacity market; rationing grid reliability among customer classes or regions; and shifting to a market focused on energy and ancillary services and away from the capacity market, PJM said in a white paper, Powering Reliability Through Market Design.

PJM will lead stakeholder discussions on the options through 2026, with the goal of developing enough of a regional consensus to move forward with market design changes, according to the white paper. “The current situation is not tenable,” PJM President and CEO David Mills said in the report. “The region has years, not decades, to make these choices deliberately.”

For years, PJM operated with more than enough power supplies to meet its needs and handle a shift away from coal-fired power plants to gas-fired generation. However, in 2024, capacity prices soared, largely driven by plans to add data centers in PJM’s footprint.

In January, the PJM board issued directives to the grid operator’s staff on how to respond to the changing circumstances. One of the directives called for a reassessment of PJM’s capacity market, which is designed to ensure the grid operator has enough power supplies three years in the future.

Currently, PJM’s capacity market faces a “credibility trap,” with the high capacity prices that incentivize new construction being undermined by government intervention aimed at lowering the prices, according to the white paper. The Federal Energy Regulatory Commission, for example, on April 28 approved an extension of a price cap and floor for two upcoming capacity auctions.

“When prices spike and unhedged load is immediately exposed, policymakers face intense pressure to intervene through price caps, emergency backstop procurements, or other administrative actions that signal to investors that the revenue they are counting on to recover their costs may not materialize,” PJM said.

In its white paper, PJM said its three proposed frameworks each have pros and cons, and aren’t mutually exclusive. The grid operator said it expects stakeholders will develop additional options.

Under Path A, the market-stabilization framework, PJM would keep its capacity market, but the vast majority of load would have to be covered through long-term capacity commitments. Capacity would clear at high prices when the system is short — maintaining an investment signal — but most load would be insulated from the high prices through forward contracts, PJM said.

The “differential reliability” path, called Path B, would create a formal plan for determining which customers could see power outages when there isn’t enough electricity to meet demand, according to the white paper.

“Path B assumes that the investment needed to return the PJM system to its desired reliability level will either not happen in a timely manner and therefore it becomes a bridge solution, or, not happen at all,” the grid operator said.

PJM is working with stakeholders on one element of the rationing approach by developing a “connect and manage” process for large loads that don’t have their own new power supplies, PJM noted.

Path C calls for making the energy and ancillary services market the central pathway for ensuring reliability, with the capacity market becoming a backstop mechanism for capacity owners to recover any revenue shortfalls.

“A well-functioning energy market can provide the revenue recovery that generators need to justify investment, making the capacity market largely redundant,” PJM said.

Shifting away from the capacity market has major advantages, but would be a multi-year process, according to PJM. The paper also said PJM could implement some combination of the proposed reforms.

“PJM may be operating on multiple tracks simultaneously: implementing Path A hedging reforms in the near term (2026–2029), piloting Path B differentiation frameworks for large new load (2027– 2030), and developing the E&AS market reforms that would make a longer-run Path C transition feasible (2028 and beyond),” the grid operator said.

Following the paper’s release, analysts with Jefferies said they expect reforms will be in place before PJM holds a capacity auction that is scheduled for May 2027.

“We are expecting reform that would ultimately result in lower capacity prices for the existing [generating] assets, while providing more longer term price signal/compensation structure for the new generation and maintaining system reliability,” they wrote in a note Wednesday. 

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By GE Vernova

Years ago, a book was published that challenged a deeply held belief of both consumer brands and the customers they serve. The Paradox of Choice: Why More Is Less argued that near limitless choices in the products we all buy at stores and ecommerce websites made people more anxious, less happy and more reluctant to make any decisions at all. Instead of feeling empowered by a bounty of options, the book concluded that fewer choices could elevate the confidence people feel in making purchase decisions.

According to the International Energy Agency (IEA), the world added 108 gigawatts of battery energy storage in 2025, an increase of about 40% compared to 2024. Though it grabs headlines for scaling so rapidly, battery energy storage is by no means the only technology utilities are considering.

Indeed, utilities now have a broader range of options than ever before to address reliability and resilience challenges. From grid-enhancing technologies (GETs) that increase the utilization of existing transmission assets, to synchronous condensers, grid-forming batteries, advanced power electronics and increasingly sophisticated digital monitoring and control systems, the industry has developed a deep and expanding toolkit for supporting grid performance. A wider selection of technologies may seem like an unalloyed good. 

But, utilities today now face a paradox of choice. The industry has more technologies available to support reliability, resilience and flexibility than ever before.  

Yet as the number of options grows, determining which solution will deliver the greatest value for a particular system challenge becomes increasingly complex. The challenge is no longer simply finding a technology that could address a given problem. Now, it’s understanding precisely what problem needs to be solved, where in the system it is emerging and which intervention will deliver the greatest value given the full range of forces and interactions at play. Put differently, utilities today have a decision problem, not a technology problem. And the analytical frameworks most utilities rely on to make those decisions were not built for the grid that is rapidly evolving.

“This is not about finding the technology,” said Gagan Porwal, Global Head of Operations, Strategy and Software for GE Vernova’s Consulting Services. “It is more about how to make a system-level decision that drives the right level of resiliency and reliability.”

Three questions every utility should be asking

Before any decision about which technology best enhances grid resilience, we must be crystal clear about the specific risks emerging and where they are located. 

Exacerbating the problem is the fact that industry-wide, we do not have a standardized framework capable of producing confident decisions at the speed necessary today. “There is a lack of a standard or a defined framework and process that can help make decisions faster and execute procurement decisions in a manner that keeps up with the rate of change on the grid, large load profiles and the requirements the system has from a resiliency perspective,” Porwal said.

Solving that decision problem starts by answering three questions.  

Question 1: Where are my emerging flexibility and stability hotspots?

It seems like an obvious observation, but it bears repetition: utilities cannot solve problems they can’t see. Traditional planning frameworks were built for a grid that behaved predictably, including dispatchable generation and evenly distributed load growth. In that environment, planners could develop a reasonable view of future system conditions and assess whether the grid would continue to perform reliably. When the range of possible outcomes was relatively narrow, those approaches were highly effective at identifying where investments were needed. 

That grid no longer exists. Load growth is emerging rapidly and unevenly. For example, a relatively small number of utility service territories and regional transmission organizations, particularly ERCOT and PJM, are experiencing double-digit load growth, while many others see only modest increases. At the same time, IBRs change power flows throughout the system that deterministic models struggle to capture, making it difficult to pinpoint where resilience challenges will emerge. Extreme weather events are creating new operating challenges. Instead of planning for a single expected future, utilities increasingly need to prepare for multiple plausible futures, each with different implications for reliability, flexibility and stability. This is driving a greater need for stochastic planning approaches, which evaluate a range of potential outcomes and uncertainties rather than relying on a single forecast of future conditions. 

Visibility is a non-negotiable precursor to any technology deployment. A utility considering where to put energy storage must first have granular, network-level analysis to see where congestion is a problem, where voltage support is needed and how storage will interact with existing grid assets. Without that visibility, technology investments are at risk and may, in fact, create more problems than they solve.

Question 2: What type of flexibility does my system actually need?

Knowing where risks to grid reliability are developing is an important first step. The second is understanding what kind of intervention best addresses them. This is where a technology-first decision framework creates unintended problems. A utility with a preferred technology solution for reliability challenges isn’t answering the fundamental question: What specific flexibility does the grid need at a precise location, given the other assets operating around it and current and future conditions?

Clarity about the flexibility needs across the grid is vital because flexibility needs are not interchangeable. For example, capacity flexibility can meet peak demand as load grows and generation portfolios evolve. Operational flexibility manages the variability introduced by wind and solar on a minute-to-minute and hour-to-hour basis. Voltage and reactive power support addresses stability challenges associated with an influx of IBRs. Each of these needs requires a different solution and deploying the wrong one wastes money without fully solving the problem.

Battery energy storage is versatile and can address ramping needs, contribute to capacity adequacy and provide voltage support. But which purpose, or purposes, it is serving depends largely on where it is installed on the grid. Utilities can cost-effectively provide the flexibility the grid needs to be reliable only when they clearly diagnose the problems and choose the technology best suited to solving them.

“Instead of taking a technology-first approach, the question always has to be: what am I trying to solve for, where am I trying to solve it and how quickly do I need to solve for it?” Porwal said. “If I know those things, then I know the most optimal combination of technology, tools and processes I need to deliver that.”

Question 3: Which solutions solve the problem and create the greatest value?

Every investment decision is ultimately a choice about how to allocate limited capital. Investment in technology solutions that don’t fully solve a reliability problem means capital won’t be available elsewhere. With load growth shortening decision timelines and interconnection queues growing, there is pressure to move fast. But speedy decisions made without visibility and analytical rigor underperform in the real world, even if they look perfect in isolation. 

A comprehensive evaluation of solutions requires comparing technologies, quantifying technical and economic tradeoff and stress-testing results against a wide range of future scenarios. A storage deployment that performs well under one set of assumptions may look very different under another. A transmission upgrade that appears cost-prohibitive in isolation may deliver significant value when its reliability benefits are fully quantified. 

Embracing this approach leads to good investment decisions. It also means decisions are defensible to the increasing scrutiny regulators, policymakers and ratepayers are applying to investment proposals. 

Moving away from a technology-first decision-making framework to a more rigorous, system-level approach is a necessity given the speed, scale and complexity of the challenges posed to grid reliability and resilience. GE Vernova’s Consulting Services helps utilities make that shift by identifying where flexibility and stability risks are emerging and pinpointing the best technology strategy to address them. 

"Our job at the end of the day is to de-risk decisions," Porwal said. "This is where we do the deep analytical work to produce an evidence-based recommendation: this is what you need to do to keep your system intact."

It is by no means a bad thing that the industry has an abundance of technology choices to enhance grid reliability and flexibility. But like the dilemma described in The Paradox of Choice, a multitude of options inevitably leads to questions about which investments are best. Those questions are best answered with clarity and visibility about the grid benefits those investments can achieve. 

The resource outlook for the Midcontinent Independent System Operator continues to improve, with excess power supplies expected over the next five years, according to a survey discussed at a workshop the grid operator held June 4, 2026.

MISO members are expected to add 15 GW a year, on average, in accredited summer capacity over the next five years, up from expectations for up to 8.6 GW in annual additions a year ago, according to the latest Organization of MISO States-MISO annual survey. The additions include 4 GW annually in fast-track Expedited Resource Addition Study projects.

The survey shows utilities are working to “help meet rapidly growing demand,” Michael Carrigan, OMS president and Illinois Commerce Commission commissioner, said at the meeting. He added, however, that “the results reinforce that maintaining reliability is becoming more complex as load growth accelerates, the resource mix evolves and reliability risks increasingly shift towards winter conditions.”

The latest OMS-MISO survey marks a turnaround from two years ago, when the survey indicated that MISO faced possible shortfalls starting in 2025. The deficits were projected to grow over the following four years.

Now, it forecasts growing power supply margins, even with loads forecast to grow by 5.1% a year.

The survey indicates that MISO will have excess supplies above its planning reserve margin for the planning year that starts in June 2027 ranging from 4.6 MW to 12.7 MW, depending on the season.

Those surpluses could continue growing. Based on load forecasts from November, the survey indicates MISO’s excess capacity above forecast planning reserve margin requirements — which includes a buffer above expected peak loads — will grow from 11.5 GW in summer 2028 to 39 GW in the summer three years later. However, when considering load forecasts from April, those margins are significantly less, according to the presentation.

In the near term, solar and battery storage make up most of the capacity additions. By 2032, the roughly 100 GW of new supplies will be about 60% wind, solar and batteries and 40% gas-fired generation, according to the presentation. 

MISO cautioned that there is uncertainty about the viability of the 87 GW of resources with signed generator interconnection agreements that haven’t been built. The grid operator said it is studying interconnection requests for another 192 GW.

So far this year, 3 GW of nameplate capacity has come online compared with 10.6 GW in all of last year, 7.6 GW in 2024 and 5.6 GW in 2023, according to MISO’s Generator Interconnection Queue Commercial Operation Dates Dashboard. Solar generation accounts for nearly 60% of the total 26.8 GW of capacity over that period.

MISO noted that it is switching to a “direct loss of load” resource accreditation methodology, which it said will value a resource’s contribution to reliability during the highest-risk periods. The change will come into effect for MISO’s 2028/29 planning year.

MISO runs the grid and wholesale power markets in 15 states and the Canadian province of Manitoba.

The OMS-MISO survey has become an increasingly important tool for states, utilities, MISO and stakeholders in understanding changing resource adequacy conditions across the grid operator’s footprint, Carrigan said.

The survey received a 99.5% participation rate, a record, he noted.

New York, New England and the Canadian provinces of Ontario, Québec, New Brunswick and Nova Scotia, are expected to have adequate electricity supplies for typical weather patterns this summer, according to an assessment published June 10, 2026.

However, under higher peak load levels there is some chance that the Maritimes, New England and New York “will need to rely on operating procedures in addition to imports to address resource shortages,” the Northeast Power Coordinating Council said in its 2026 Summer Reliability Assessment. The higher peak load levels have a roughly 7% chance of happening, according to the report.

And a probabilistic assessment suggests that operators in New York and New England “will likely need to implement emergency operating procedures” and/or issue energy emergency alerts during periods of higher-than-expected demand and low-probability reduced resource conditions, according to the report. The greatest risks occur in July and August, “demonstrating concerns under extreme conditions.”

“From the broader regional perspective, the NPCC assessment shows that the region has sufficient transmission capability and the resources needed to reliably meet its summer peak demand for a wide range of system conditions,” NPCC President and CEO Charles Dickerson said in a statement. “If needed, established operating procedures are available to maintain reliability and keep supply and demand in balance.”

The assessment anticipates summer peak demand of about 105,000 MW, just 400 MW higher than last summer’s forecast. The region is projected to have about 158,000 MW of installed capacity available to meet demand, which is about 1,700 MW higher than last summer “in part due to the additional gas and storage facilities expected to be available in Ontario,” NPCC said.

Québec, which sees its electricity demand peak during the winter months, “is expected to meet forecast electricity demand by a wide margin enabling transfers of surplus electricity supplies to other areas of the region,” the coordinating council said.

And transmission projects recently completed in New York and New England “have reinforced overall regional reliability for this summer,” said Phil Fedora, NPCC chief engineer and senior vice president of external affairs.

The 1,250 MW HVDC Champlain Hudson Power Express transmission project is designed to bring hydropower from Québec directly to New York City and as of mid-May was in its final testing phase. NPCC’s probabilistic analysis assumed its availability for the entire summer assessment period.

The addition of 58 GW of summer resource capacity has the U.S. grid in good shape heading into the summer months, but risks are growing during the shoulder seasons, the North American Electric Reliability Corp. said May 19, 2026, in its annual summer assessment.

The watchdog’s report flagged four areas at risk of energy shortfalls or local constraints during extreme heat conditions this year, down from six in 2025.

The pace of electricity demand growth continues to rise, and NERC officials highlighted difficulties in demand forecasting due to data center interconnection issues and evolving operational data. Summer peak demand this year will be about 865 GW, according to the assessment, up from about 842 GW in 2023.

A “large influx” of bulk power system resources over the past year “has outpaced demand and is boosting reserves,” according to the report. Resources available to meet peak demand this summer jumped by over 58 GW over last year, including 16 GW of solar, 15 GW of storage and 7 GW of gas capacity.

Another 19 GW of capacity additions include other types of resources and changes to generator availability, including the completion of nuclear outages and maintenance plans. NERC said 16 of its 23 assessment areas have increased available capacity ahead of summer.

“Overall, this is a positive story,” NERC analyst Suzanne Edwards said in a call with reporters to discuss the assessment. 

The Midcontinent Independent System Operator and Electric Reliability Council of Texas markets both saw “a robust jump” in year-over-year anticipated resources, of 7% and 12%, respectively, allowing each to shed the “elevated” risk assessment from the previous summer’s assessment, Edwards said.

NERC’s report flagged parts of New England, the Northwest, SaskPower’s territory in Canada and a local area in West Texas as facing elevated risks in extreme heat.

In NPCC-New England, firm import commitments have declined since last year “resulting in lower operating reserves and increased reliance on non-firm supplies from neighboring systems to meet high demand,” NERC said. In WECC-Northwest, persistent drought conditions, rising demand and a decline in resource capacity “could increase vulnerability during more extreme summer conditions.”

In the SaskPower area, a higher demand forecast reduced operating reserves. And while ERCOT was broadly removed from the “elevated risk” designation, a small area in the western portion of the state “remains at risk for load disruption when solar and wind output is low and transmission constraints limit the flow of imports.”

West Texas “has a bit of everything, with respect to our big reliability topics of the day,” Edwards said. “There is definitely large load growth, and that's complicating the load forecast when the rate of completion is not super stable.”

Data center growth has muddled the demand picture in Texas, and ERCOT in April preached caution on its own projections. The grid operator estimated summer peak load to range between 90,500 MW and 98,000 MW, significantly cutting the 112,000 MW peak it forecast in a previous report that included large-load demand estimates from utilities at the direction of state lawmakers.

The Texas Interconnection is “widely at a normal risk level” this summer due the jump in anticipated resources as well as a 4.5% decline in projected net internal demand, NERC said. The lower demand forecast is the result of “updated load modeling that reflects the observed behavior of load during peak periods and more demand response from large computational loads.”

“On a regional basis we have seen some downward revisions in the demand associated with large load interconnection rates in certain areas,” Edwards said. Large loads, including data centers, have “been difficult to time, with respect to the speed at which they connect to the grid. Slower than expected interconnection rates have spurred these adjustments to the near-term load forecast,” she said.

“The trend is also visible in [the PJM Interconnection], with lesser growth expected. It's not quite as stark as a full on decline in demand, but lesser growth,” Edwards said.

In January, PJM trimmed its load growth forecast through 2032 on stricter data center vetting and the economic outlook in its operating footprint.

NERC warned that sudden load reduction events or disconnections are a growing concern with data centers and “pose operational challenges for the upcoming summer.” Earlier this month, NERC issued a Level 3 alert and mandatory actions, following instances of data centers unexpectedly dropping load or oscillating demand rapidly, creating reliability concerns.

Other reliability risks NERC is watching this summer include wind droughts. The bulk power system grew its wind capacity 3% year on year, NERC said.

“The impact of wind ramp events — particularly down ramp — must be anticipated and planned for such that appropriate resources are ready to replace the energy lost during these conditions,” the summer assessment said. “It is not uncommon for areas to experience several thousands of megawatts of wind energy coming off-line during these events.”

Increasing grid complexity, rising demand and shifting temperatures are also driving up reliability risks in the spring and fall, seasons typically thought to be safer from reliability challenges, officials said. The overlap of early summer heat and spring maintenance outages can lower operating reserves, the assessment noted.

“There is trending higher risk in shoulder periods than in ... the summer peak conditions, and I think that's a really reflection of how we're using electricity [and] the types of resources that are being provided to us,” said John Moura, NERC director of reliability assessments and performance analysis.

A report by Energy Ventures Analysis for the Natural Gas Council concluded that reforms implemented following Winter Storm Uri in 2021 helped insulate the electric grid from outages during Winter Storm Fern in January 2026, even amid near-record consumption driven by sustained cold across the Central and Eastern U.S. 

The report credited winterization investments, flexible liquefied natural gas operations and large-scale storage withdrawals with helping to maintain system reliability during the event, noting that storage supplied roughly 30% of total U.S. gas demand during peak periods. 

Although the report found improvements have been made to the interconnected energy system since 2021, it also concluded “the full stress test of post-Uri improvements has not yet occurred under Uri-level temperature conditions,” and continued effort is needed. The authors recommended stronger gas-electric coordination, including firmer fuel assurance for generators, protections for critical gas infrastructure during grid emergencies and continued investment in pipeline and storage capacity. 

At more than 40%, gas is the largest single source of electricity generation in the U.S. The findings come as utilities and regulators head into summer storm season and grapple with how to balance rapid load growth from electrification, data centers and industrial demand against increasingly weather-driven system stress. 

Pawan Vaswani, vice president of energy and commodities strategy at AI platform developer Publicis Sapient, speaking independently of the report, said operators need a better understanding of where bottlenecks could emerge across interconnected energy systems during extreme conditions.

“Weather events tend to expose dependencies that may not be apparent under normal operating conditions,” Vaswani told Utility Dive in an email. “[A] constraint in one part of the system can create pressure across the rest of the value chain.” 

As many utilities and hyperscalers invest in new gas-fired generation, the EVA report adds to ongoing discussions over whether reliability planning should account not only for generation capacity but also for the pipeline and storage infrastructure that supplies those plants.  

Among other things, the report, “Holding the Line: U.S. Natural Gas Performance During Winter Storm Fern,” called for electric market design reforms to encourage electric generators to secure firm capacity and services commensurate with their fuel security obligations, rather than rely on interruptible arrangements.

"Natural gas storage is a critical component of the U.S. energy infrastructure, providing system reliability, stabilizing market prices, and enhancing resiliency during high-demand periods and unexpected disruptions," the report said. 

The report also urged federal and state officials to consider rules exempting critical natural gas facilities from load-shedding plans so they are not cut off during electric emergencies.

It warned that structural constraints remain in key regions, particularly the Northeast, where limited pipeline capacity contributed to sharp price spikes during the storm. In some locations, prices surged to historically high levels during peak demand periods, reflecting congestion as well as underlying supply conditions, it said. 

The study also models alternative pipeline scenarios and finds that additional capacity in constrained markets could have significantly reduced regional price volatility during Fern, while also reducing reliance on a higher-emitting backup supply such as fuel oil in parts of New England. 

Specifically, the data show monthly average winter prices at key Northeast hubs would have fallen by 10% to 20% if four delayed or canceled pipeline projects — Access Northeast, Transco Northeast Supply Enhancement, PennEast and Constitution Pipeline — had been built, with even steeper reductions on peak-demand days.

“Overall, natural gas reliability for natural gas utilities depends on sustained infrastructure development and maintenance, operational preparedness, and multiple supply and balancing tools working together during weather events,” the report said. 

The U.S. Department of Energy’s secretary has broad authority under the Federal Power Act to declare emergencies to keep power plants from retiring, and those emergencies don’t have to be imminent, DOE told a federal appeals court last week in response to challenges over its orders keeping a Michigan coal plant online.

“The statute’s text grants the Secretary discretion to determine that an emergency exists,” DOE said in a March 17 brief with the U.S. Court of Appeals for the District of Columbia Circuit. “This expressly includes a sudden increase in demand, a shortage of generation facilities, or other causes.”

The brief is the DOE’s first defense in court of the 90-day emergency orders it began issuing last year to prevent fossil-fueled power plants from retiring. So far, the orders have targeted six power plants — all but one coal-fired — totaling about 4,300 MW.

Generally, in those orders, DOE said the power plants need to keep running to prevent blackouts in the face of rising electric demand. The DOE has not allowed any of those orders to lapse, using its authority under the Federal Power Act’s section 202(c) to issue new 90-day orders when the old ones expire.

The brief was in response to challenges brought against the DOE over its May 23 order directing Consumers Energy to continue running the 1,407-MW, coal-fired J.H. Campbell power plant in West Olive, Michigan, past its May 31 retirement date. The department has renewed that order three times since.

Michigan, Minnesota and Illinois as well as the Sierra Club and other groups have challenged the emergency order. In part, they contend that DOE failed to show the Midcontinent region around the Campbell power plant faces an energy emergency.

In its brief, DOE said the Federal Power Act defines emergency broadly.

“It does not require imminence or an unexpected development,” DOE said. “The Secretary is also granted broad discretion to use his ‘judgment’ on what ‘will best meet the emergency and serve the public interest.’”

Moreover, the statute lacks strict procedural requirements, according to DOE.

“Contrary to Petitioners’ contentions, the Secretary was not required to prepare any particular analysis, weigh alternatives, or to select the best theoretically possible emergency response,” the department said.

When DOE considered issuing an emergency order for the Campbell power plant, the department found that electricity demand was rising, major power plants were retiring and new power sources weren’t coming online fast enough, it said. The Midcontinent Independent System Operator was at “elevated risk” for reliability problems and higher than normal temperatures were expected, DOE told the court.

“The Secretary interpreted the totality of this evidence and applied his expertise to find that an emergency exists,” DOE said.

DOE noted that Secretary Chris Wright ordered the Campbell plant to operate under “economic dispatch” to reduce ratepayer costs.

If the court finds a legal flaw in the 202(c) order, it should send the issue back to DOE instead of vacating the order and limiting its ability to issue similar orders, government lawyers argued.

“The Secretary must be able to use section 202(c) to protect public health and safety, particularly in anticipation of extreme weather events like the recent Winter Storm Fern and the ensuing, prolonged cold snap,” the DOE said.

In the seven months after DOE ordered the Campbell plant to stay online, it produced 3.6 million MWh, down 39% from 5.9 million MWh generated over the same period in 2024, according to the latest U.S. Energy Information Administration data. 

Consumers Energy spent about $254 million keeping the Campbell plant operating per the DOE orders through December, according to a Feb. 10 filing at the U.S. Securities and Exchange Commission. It received $119 million in revenue from running the plant in the second half of last year and has asked the Federal Energy Regulatory Commission for permission to recoup $135 million in costs from MISO ratepayers, said CMS Energy Corp., which owns Consumers.

Consumers urged the appeals court in a brief to not weigh in on the cost-recovery issue, which is being handled by FERC.

The utility asked the court to “avoid unintended consequences for those separate proceedings, including making clear that any decision here does not assume the availability of refunds or otherwise affect FERC’s decision-making in those separate proceedings.”

DOE continues to issue emergency orders to keep other fossil-fueled power plants running. On March 16 it issued its second emergency order for TransAlta’s 730-MW, coal-fired Centralia power plant in Washington. The company must make the plant available to run until mid-June under the order. The company had planned to shut it down at the end of 2025.

TransAlta’s president and CEO, John Kousinioris, said during an earnings call in February that the company was complying with the orders, but he did not expect the plant to run given “how flush” the state was with hydropower.

“Our primary focus is more on getting clarity on the existing order,” including how TransAlta will recoup its expenses from keeping the unit online, Kousinioris said.

Other generators under 202(c) orders are in Colorado, Indiana and Pennsylvania.

Reliability risks are spreading across the bulk electric system, driven by soaring peak demand forecasts and lagging resource additions, the North American Electric Reliability Corp. said Thursday in its annual Long Term Reliability Assessment. 

Summer peak demand across the bulk system is forecast to grow by 224 GW over the next 10 years, a more than 69% increase over the 2024 LTRA forecast and a 24% increase from 2025 peak demand, NERC said. New data centers account for most of the projected increase. Winter demand growth is even higher, with 246 GW of growth forecast over the next decade.

The Midcontinent Independent System Operator, PJM Interconnection, Electric Reliability Council of Texas and parts of the Pacific Northwest all face a high risk of insufficient reserve margins or exceeding unserved energy criteria at some point within the next five years, according to the report.   

“The system is changing faster than the infrastructure needed to support it,” John Moura, NERC's director of reliability assessments and performance analysis, said in a call with reporters. We are “in a period here where future electricity supply has never been more uncertain.”

From 2024 to 2025, existing capacity from fossil-fueled generators fell by 21 GW, while bulk power system capacity for peak demand hours from battery, wind, and solar resources increased by 23 GW, according to the report.

Bulk power system capacity “fell short of projections this year,” said Mark Olson, NERC’s manager of reliability assessments. “And that was the case last year as well,” he added. Delays in connecting new resources and unanticipated generator retirements are the cause of the miss.

In a change from last year’s LTRA, NERC said solar PV is no longer the sole, predominant generation type planned over the next 10 years.

“New battery resource projects have grown to match solar projections, and, together, solar and battery capacity additions represent two-thirds of the Tier 1 and Tier 2 resources in this year’s 10-year LTRA study period,” the report said.

“Those provide good capability for meeting summer peak demand, but the capability of resources in the winter is very different,” Olson noted.

Natural-gas-fired generator additions represent 15% of the projected capacity additions followed by wind and hybrid resources at 8% each.

Projected generation retirements have shrunk from the 2024 reliability assessment. Confirmed and announced potential retirements over the next 10 years “remain high and total over 105 GW in peak seasonal capacity,” NERC said, but that is “roughly 10 GW lower than the 10-year retirement projections last year.”

All areas are adding resources and working to ensure grid stability, NERC said. But some face high risks over the next five years. 

In MISO, projected resource additions “do not keep pace with escalating demand forecasts and announced generator retirements,” NERC said. In PJM, the grid operator’s anticipated resource margin will fall below a reference level starting in 2029.

In ERCOT, NERC said probabilistic unserved energy metrics for 2026–2027 have improved since the 2024 LTRA, “but continued rapid load growth outpaces projected resource additions in later years.” In parts of the Northwest, near-term resource additions “are predominantly solar PV, leading to a more variable resource mix,” and there is a growing unserved energy risk in summer and winter.

Industry groups responded, calling for policies to speed resource development and maintain existing plants.

“Poor grid operator interconnection processes, as well as overly cumbersome state-level siting and permitting rules, need urgent attention,” Caitlin Marquis, a managing director at Advanced Energy United, said in a statement. State leaders and grid operators “need to remove the red tape blocking deployment of the most cost-effective and fastest-to-build resources, including solar, energy storage, and demand-side resources.”

The Electric Power Supply Association, which represents competitive generators, said the industry is focused on adding new resources but also needs policies to keep existing plants online.

“Reliability is best served by competitive electricity markets that send clear, durable development signals — not by policy interventions that create misalignment between supply and demand,” EPSA President and CEO Todd Snitchler said in a statement. “In order to address the warnings NERC’s LTRA sets out, it will require getting market signals right while addressing permitting and siting delays, supply chain bottlenecks, and other barriers to development.”

America’s Power, which represents coal generators, called NERC’s assesment “another sobering wakeup call.”

“Utilities have announced plans to retire more than a fourth of the nation’s coal power plants over the next five years. Most of these retiring coal plants are located in high-risk regions,” America’s Power President and CEO Michelle Bloodworth said in a statement. “Unless these retirement plans are reversed, the grid will lose an energy-secure, affordable, and reliable source of baseload power.”

The issue of data centers — and how to ensure they can be safely added to the grid — was a key focus of a grid reliability conference held by the Federal Energy Regulatory Commission on Tuesday.

Generally, grid reliability is strong in the United States, but challenges are growing, Jim Robb, president and CEO of the North American Electric Reliability Corp., said at the meeting.

“The reliability of the power grid remains extremely high, but, paradoxically, the risks to reliability continue to mount,” Robb said. “We're seeing … an increasing number of small scale events and near misses that continue to reinforce what we can't call anything but a five-alarm fire when it comes to reliability.”

According to Robb, grid reliability challenges include dwindling resource adequacy with weakening reliability services, extreme weather, interdependency with natural gas and other sectors, especially telecommunications, policies affecting resource and fuel development, load development, the ability to site and permit needed infrastructure and an “escalating toxic soup” of physical and cybersecurity risks.

The U.S. faces potential imbalances between electricity supply and demand amid uncertainty about how much load may be coming online and how much generation and transmission must be built to handle it, said FERC Commissioner Judy Chang, warning that the risks and uncertainties around those issues are “coming to a head.”

Estimates in data center growth range widely. The U.S. Department of Energy in December said U.S. data centers could use 6.7% to 12% of all U.S. electricity by 2028, up from 4.4% in 2023.

The U.S. needs to build energy infrastructure more quickly, according to FERC Chairman David Rosner.

“I see our grid as needing every single megawatt, every single electron and every single molecule we can get to meet demand on those peak days and peak hours,” Rosner said. “That means we need to make sure that we're studying faster, we're giving permits faster and unlocking all different types of energy infrastructure that are needed.”

The power sector needs to move quickly to address reliability challenges, according to Jennifer Curran, senior vice president of planning and operations for the Midcontinent Independent System Operator.

“Where we are today, I would say, is not safe because we are in a tight reserve margin situation,” Curran said. “We are in a situation where we do have new types of resources coming on, and we are going to have to make our best steps to continue to increase reliability.”

Given the uncertainty, Curran called for ensuring the grid system has adequate “shock absorbers,” such as improved data analysis tools.

“How do we make sure that we have both in our physical grid and in our market products … the right incentives to make sure that we are able to bear these uncertainties that are really going to be coming before us?” Curran asked.

“The best thing we can do is get better at quickly dealing with the uncertainty and having as much built-in infrastructure as we can to really provide that balance of reliability and economic efficiency,” she continued. “Getting the transmission built to help provide those connections and provide that optionality within the system is something that's really important, and it takes a long time.”

Electricity affordability and the grid buildout

Dealing with some of those challenges will be costly, according to FERC Commissioner Lindsay See.

“Some of that is inevitable, but we are reaching a point where bills are becoming incredibly difficult for people across the country,” See said.

Some states are taking measures to try and shield ratepayers from costs associated with data centers and other large loads.

Tricia Pridemore, a commissioner at the Georgia Public Service Commission, said with appropriate guardrails, large data centers can help reduce electric rates.

In Georgia, large loads enter into 15-year contracts to pay for all the new generation, transmission and distribution needed to manage their load, Pridemore said. The PSC recently approved a plan for Georgia Power to add 7.1 GW of capacity to meet growing demand, which the commission estimates will reduce residential rates by $2.64 a month, she said.

Matthew Holtz, vice president of transmission operations at Invenergy, said merchant transmission, which is paid for by entities buying capacity of transmission lines, can take cost burdens off ratepayers.

Invenergy is also calling for “cloud-based” system monitoring, which Holtz said could lead to more economic energy and capacity sharing between regions and help respond to extreme weather events.

Long-term and more integrated system planning that co-optimizes transmission, generation and load solutions could put downward pressure on electric rates, according to Carlos Casablanca, managing director of distribution planning and analysis at American Electric Power.

“We are seeing … a lot more costs coming: the build out that needs to occur to accommodate large loads, and also the resources that are required to both address retiring generation but also meet the need from the large loads,” Casablanca said. “So anything we can do in the planning space to prepare for what's coming and optimize as early as we can, it'll help. It'll pay dividends down the road.”

U.S. electricity customers experienced an average of 11 hours of power outages in 2024, nearly twice as many as the annual average across the previous decade, according to a new report from the Energy Information Administration.

Hurricanes accounted for 80% of those lost hours, with most of last year’s outages resulting from major weather events like hurricanes Beryl, Helene and Milton, EIA said in the report released Monday.

“Interruptions attributed to major events averaged nearly nine hours in 2024, compared with an average of nearly four hours per year in 2014 through 2023,” EIA said. “Service interruptions that aren’t triggered by major events routinely average about two hours per year.”

Customers in South Carolina were significant outliers in terms of outage duration, the report said, experiencing an average of 53 hours of outages in 2024. Much of this was due to last September’s Hurricane Helene, which left 1.2 million customers in South Carolina without electricity.

The report appears to build on a growing body of evidence that extreme weather is taking a heavier toll on the electric power system in parts of the country. In October, JD Power released a report that found the average length of the longest outages are getting longer and concluded that disasters have become a “fact of life” for many utility customers. 

Helene, in particular, caused severe damage to utility systems in the U.S. Southeast and Mid-Atlantic.

Duke Energy said after the hurricane that transmission infrastructure in upstate South Carolina “was severely damaged and, in many cases, destroyed” and would need to be entirely rebuilt.

Three days after the hurricane struck, 900,000 Duke customers remained without power across North Carolina and South Carolina, the utility said. Following hurricanes Helene and Milton, Duke reported needing to replace around 16,000 transformers — more transformers than utilities generally require in an entire year, WoodMac Senior Analyst Ben Boucher said in February.

South Carolina, along with North Carolina and Florida, “dealt with strong winds and flooding from Hurricane Helene that affected transmission and distribution power lines as well as substations leading to prolonged power outages,” EIA said. The following month, Hurricane Milton “left 3.4 million customers in Florida without power,” it added. 

“In contrast, customers in states such as Arizona, South Dakota, North Dakota, and Massachusetts experienced, on average, less than two hours of service interruptions in 2024,” EIA said

While Hawaii averaged less than 10 hours of total outages throughout the year, the state saw more frequent interruptions — an average of 4.4 interruptions per customer, compared to the U.S. average of 1.5, “mainly due to adverse weather, volcanic activity, unexpected outages at oil-fired plants, and issues connecting new generating capacity,” EIA said.