Reliability

The PJM Interconnection is considering bolstering its interconnection reliability requirements for “computational loads,” such as data centers and crypto-mining facilities, the grid operator said August 11.

The move to consider “ride-through” standards and other requirements comes after about 3,800 MW of data center load tripped offline in northern Virginia on July 22, the latest and largest such event in PJM’s history, the grid operator said.

The event — triggered by a fault on a 230-kV line in Dominion Energy’s zone — caused a high imbalance between generation and load, and large swings in voltage and frequency, PJM said.

During the event, which occurred in two waves, PJM’s overall load fell about 3.8% to 96,205 MW from 99,984 MW, according to the grid operator, which runs the electric system and wholesale power markets in 13 Mid-Atlantic and Midwest states and the District of Columbia.

PJM said it recovered the Balancing Authority Area Control Error Limit — a measure of the imbalance between sources and uses of power — within nine minutes, compared with North American Electric Reliability Corp. standard of 30 minutes, and dispatched reactive power resources to lower system voltage.

Two similar events in Dominion’s zone in northern Virginia — home to the largest data center cluster in the world — caused sudden load transfers of about 1,500 MW each in 2025 and 2024, PJM said.

The issue was discussed at an Aug. 6 PJM Operating Committee meeting where PJM staff said data centers may be too sensitive to grid conditions.

“This was a normally cleared fault,” Operating Committee Chair Emanuel Bernabeu said at the meeting, per PJM. “They should not disconnect from the grid. These data centers are too sensitive to the kind of voltage that they like, and we feel they are disconnecting too early.” 

As a result, PJM is evaluating a possible expansion of its reliability requirements, “with consideration of existing and future industry ride-through standards and practices,” Matthew Wharton, PJM manager of reliability engineering, said.

PJM’s effort comes as the NERC is moving to set reliability requirements for computational loads.

Under a Federal Energy Regulatory Commission directive, NERC is set to finalize by Dec. 31 registry criteria and initial reliability standards for adding computational loads to the bulk power system. NERC will also develop a plan by March for setting additional reliability standards for computational loads.

However, NERC will not address minimum voltage or frequency ride-through requirements until some time next year, according to PJM.

“You really need these requirements in place before the load comes on the system,” David Souder, PJM executive director of system operations, said at the meeting.

The Texas Public Utility Commission on July 9 unanimously approved rules that will require large computational loads, like data centers and crypto-mining facilities, within the Electric Reliability Council of Texas footprint to stay stable and connected to the grid through disruptions.

Modern computational loads, Kenteel Engineering said in a June blog, are “engineered to protect extremely sensitive and expensive equipment,” and during a voltage dip are programmed to disconnect or enter momentary cessation.

However, this presents a reliability problem, Kenteel Engineering said, as when “several hundred — or several thousand — megawatts of computational load all detect the same sag and drop simultaneously, the grid experiences a sudden, large loss of demand.”

“As LCLs increase on the ERCOT System, similar events would be expected to increase in magnitude and frequency, leading to frequency instability and other reliability problems absent frequency and voltage ride-through requirements,” the Texas PUC rules state. 

The rules don’t immediately penalize facilities that fail to ride through a qualifying event, Kenteel Engineering noted, but instead put them “on the clock” to investigate and report the root cause within 90 days of ERCOT’s request, “develop a corrective plan within 90 days of completing that investigation, and implement the approved plan within 180 days unless ERCOT grants more time.”

“Overriding all of that, if ERCOT judges that continued operation poses an imminent risk to local or system reliability, it can order the [large electric load] — and keep it disconnected — until the Customer demonstrates compliance to ERCOT's satisfaction,” Kenteel Engineering said.

In comments, the Data Center Coalition argued that the PUC lacks the statutory authority to “impose the binding and ongoing operational requirements contained in [the rules] directly on retail customers — a category of entity that the Legislature deliberately excluded from ERCOT’s authority.” 

Texas Industrial Energy Consumers made similar comments, writing, “Unlike Market Participants who must agree to comply with and be bound by all ERCOT Protocols as a condition of participating in the wholesale market, pure retail loads have made no such commitment and have no such obligation.”

TIEC also argued that ERCOT lacks the expertise to “develop reasonable operational requirements for complex, costly manufacturing equipment. It is completely inappropriate to give ERCOT the ability to directly regulate businesses who are not participating in the wholesale market and are not otherwise regulated entities.”

In a staff memo from the PUC’s R. Floyd Walker, senior counsel with the commission’s market analysis division, Walker dismissed concerns over the PUC’s authority. Those commenters “seem to be working under the assumption that explicitly statutory authority is required,” he wrote. “Staff respectfully submits that delegated authority is sufficient.”

“There is no debate that voltage and frequency excursions on the transmission network create reliability concerns, which increase with the interconnection of each new large computational load,” Walker said. “Accordingly, if approved by the Commission, the provisions of [the rules] would be within ERCOT’s authority by virtue of that approval.”

Comments from the Texas Blockchain Council argued that proposed mitigation approaches for LCLs, such as the installation of dedicated battery storage, “are neither practical nor economical at scale.”

“While battery solutions have been suggested, we are not aware of any that have been successfully tested or deployed at the scale required for [LCLs],” the group wrote. “Even if pursued, mandating dedicated batteries for each facility would be unlikely to fully resolve the underlying technical challenges and would impose substantial costs, currently estimated at more than $1.6 million per MW, making such an approach economically prohibitive for most operations.”

ERCOT staff approved of the rules, writing in a market impact statement that they provide “necessary requirements to reduce the reliability risk posed by LCLs unexpectedly tripping or transferring to backup generation when frequency and voltage excursions within a specified range occur.”

In official comments, ERCOT wrote that LCL loss wasn’t a hypothetical, and ERCOT “has experienced 28 events involving LCL trips of at least 100 MW due to voltage and frequency excursions since the beginning of 2023. This risk will increase exponentially with the significant growth of LCLs expected in the ERCOT Region.”

Developers have requested studies for more than 438 GW of large load projects within ERCOT’s footprint, and “even if only a small fraction of these projects materialize, this will significantly increase the risk that cascading outages could occur due to LCL failures to ride through typical voltage or frequency disturbances,” ERCOT said.

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Why replace an existing or aging HPFF system?

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One of the primary concerns is the dependence on dielectric fluid and associated pressurization equipment. Traditional HPFF systems require pump plants, reservoir tanks, controls, alarms and routine maintenance to maintain operating pressure. As these systems age, utilities often experience rising maintenance requirements and greater complexity in keeping auxiliary equipment operational.

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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.

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.

Meeker Energy, a member-owned electric cooperative serving about 10,000 homes and businesses in central Minnesota, is typical of many non-profit utilities across the country. While investor-owned giants tout the profit potential of large-load pipelines in the gigawatts, distribution coops like Meeker are watching the wholesale cost of electricity rise, with little they can do to mitigate it except controlling for their own consumption. That expense accounts for the largest part of members’ bills. 

That’s where storage comes in. The utility is in the early stages of testing behind-the-meter residential batteries at members’ homes for resilience and demand response.

Steve Kosbab, Meeker’s energy services manager, said 60% of its members participate in at least one of its load management programs, which already helps Meeker reduce wholesale power demand charges.

“We’re at a level of demand response where we can only shed so much … so we’re looking at how we can enhance demand response programs that are very mature and very successful,” Kosbab told Utility Dive.

Kosbab said Meeker considered incentives for its rural and exurban customer base to add standby generators that run on propane or natural gas, but “a person could get upside down on the fuel costs versus the electric savings” with such equipment. Partial- and whole-home batteries seemed to make more economic sense, he said. 

Storage is on the rise across the power sector and on both sides of the meter. As the technology evolves, prices have fallen and capacity has gone up. At the same time, generator retirements and rising demand have caused the grid’s reliability watchdog to warn of potential electricity shortfalls, leading everyone – from residents to hyperscalers to utilities – to invest in storage as a backup in case of a blackout or curtailment, as well as a hedge against price spikes. 

Last summer, rural electric cooperatives had 439 MW/1,047 MWh of operating battery energy storage projects, according to the National Rural Electric Cooperative Association. 

Those numbers do not necessarily include every behind-the-meter battery in cooperatives’ service territories. They also represent a tiny fraction of the 28 GW/57 GWh of energy storage that Benchmark Mineral Intelligence says connected to the U.S. grid in 2025. 

But a lot more could come online soon: NRECA is tracking dozens of smaller-scale projects in development that it says could more than triple rural cooperatives’ energy storage capacity by 2028.

Many of the projects pursued by non-profit utilities will connect to the distribution networks they manage. And a significant amount of the planned capacity will be behind individual members’ electric meters.

Guadalupe Valley Electric Cooperative, which serves a rural-to-suburban region east of San Antonio, said last month it would expand a pilot with Base Power that installs heavily discounted residential batteries. It expects the program to grow from 2 MW to 50 MW over the next few years. 

In the Electric Reliability Council of Texas territory, the distributed approach is more cost-effective than deploying grid-scale storage, general manager Darren Schauer told Utility Dive. 

NRECA says initiatives like these will help shave costly demand peaks, firm intermittent generation, boost resilience and defer infrastructure upgrades. Some energy storage projects will hook up to transmission grids managed by regional cooperatives.

Beth Soholt, executive director of the Clean Grid Alliance, which focuses on the Midcontinent Independent System Operator region where Meeker is located, said cooperatives are eager to adopt new technologies when it’s in their members’ interest, and may not need the “carrots and sticks” state policymakers and regulators use to push investor-owned utilities to innovate.

“Cooperatives really can be innovative,” Soholt told Utility Dive in an interview. “I’ve been impressed over the years how they’re able to pick up on new things and just do them.”

Peak shaving and profit models

In addition to deploying batteries with colocated renewables and encouraging members to use their own energy storage, some cooperatives are also leaning into storage on the distribution system for reliability and economic reasons.

Earlier this year, Blue Ridge Power Agency, a Virginia power wholesaler for municipal and cooperative electric utilities, announced plans to deploy about 25 MW of distribution-connected energy storage at five sites owned by three member utilities. The batteries will charge during periods of low demand and discharge during periods of high demand, providing a source of peak power capacity amid sharply rising load growth in Virginia and the broader PJM Interconnection, BRPA said.

The Electric Power Board of Chattanooga, Tennessee, has 45 MW/95 MWh of front-of-the-meter energy storage in service now and plans to double that capacity over the next 12 months, Ryan Keel, its president of energy and communications, told Utility Dive earlier this year.

One of the new deployments will be a four-hour system anchoring a microgrid in a mountainous area outside central Chattanooga that has a tenuous connection to the main grid and is prone to outages.

But the utility uses most of its existing and planned battery capacity to shave demand peaks. It buys wholesale power from the Tennessee Valley Authority, whose monthly demand charges can account for one-third of EPB’s total power purchase costs, Keel said.

TVA bases each month’s charge on the hour of highest demand, “so whenever that hour occurs, we have a financial incentive to reduce that peak with energy storage and other measures,” Keel said.

That incentive is especially pressing for not-for-profit utilities that — unlike investor-owned utilities — do not earn a regulated rate of return on capital investments, many cooperative and municipal utility leaders say.

The debate over how that profit model influences storage programs was on full display in Minnesota, where regulators recently approved investor-owned Xcel Energy’s Capacity*Connect pilot, a novel type of virtual power plant that will see up to 200 MW of utility-owned distribution-connected storage deployed by 2028.

Representatives from a coalition of nonprofits opposed the utility-owned framework, as opposed to one allowing third parties to aggregate customer-owned resources. They claimed Capacity*Connect would shift financial risk to captive ratepayers and deliver significantly less value than a superficially similar virtual power plant Xcel plans to deploy in Colorado with participation from customer-owned assets.

Xcel spokesperson Kevin Coss told Utility Dive that cost-benefit analysis “is one tool out of many” that the company uses to evaluate potential programs — one that is “inherently limited because it does not consider qualitative benefits or as-yet-unknown potential value,” he added.

Coss said Xcel “expects to measure and evaluate the ongoing costs and benefits of the program” and report them in both quarterly filings and “interim program assessment” to be released by August 2028.

Xcel has said Capacity*Connect will complement its growing renewable generation portfolio and preserve dispatchable capacity as it retires thermal assets in Minnesota. Even if its approach to distributed energy storage differs from some cooperatives’, Soholt said the program and hundreds of megawatts of more traditional utility-scale projects in MISO’s northern zones will produce valuable lessons for the region’s not-for-profit utilities.

Reliability, fuel savings drive nonprofit utilities’ BESS adoption

Energy storage is particularly appealing for non-profit utilities serving communities in remote or isolated communities with limited transmission.

In rural Alaska, Homer Electric Association installed a 46.5 MW/93 MWh BESS in 2022 to boost reliability in a remote coastal area served by a single 115-kV transmission line. An outage on that line can cost the association upwards of $20,000 per day in added fuel costs, HEA executives said at the time. In 2024, HEA got a $100 million U.S. Department of Agriculture loan to add another 45 MW/180 MWh BESS nearby. 

Several hundred miles north, near Fairbanks, the Golden Valley Electric Association will use its own $100 million USDA loan for two cold-hardened 46 MW/92 MWh BESS units that it says will boost reliability, reduce fuel costs and provide spinning reserve service.

In March, the Hawai’i Public Utilities Commission approved a 43 MW/172 MWh solar-plus-storage project that will cover nearly 20% of Kaua‘i Island Utility Cooperative’s load. KIUC says the project will significantly reduce its fuel costs, saving the cooperative and its members an estimated $365 million over 25 years — up to $21 per month for the average residential customer.

In North Carolina, Tideland EMC operates a nearly 10-year-old microgrid that pairs a 3-MW diesel generator with a 1-MWh battery and a small solar array to back up storm-prone Ocracoke Island’s mainland grid connection. 

And Nevada’s Valley Electric Association plans to add two BESS arrays to its sparsely populated territory northwest of Las Vegas: a 35-MW bulk installation that will help mitigate power costs and integrate renewable energy, and a 2-MW solar-plus-storage facility in a remote valley community whose sole grid connection is vulnerable to wildfire-related public safety power shutoffs.

Energy storage also offers clear value for not-for-profit utilities in more populous areas with robust transmission connections, including for the entities that own the transmission assets themselves.

For example, the Tennessee Valley Authority, the country’s largest public power entity, aims to add 1.5 GW of energy storage capacity by 2029, starting with a 200 MW/800 MWh deployment in Alabama. 

Larger distribution cooperatives also see the value in bigger energy storage installations that provide critical capacity and help avoid potentially costly system upgrades.

Connexus Energy, which has about 150,000 members across east-central Minnesota, built the state’s first megawatt-scale grid batteries in 2018. Those early systems, totaling 15 MW/30 MWh of storage capacity, initially charged off colocated solar but now draw from the grid as well, Tessa Haagenson, Connexus vice president of power supply, told Utility Dive.

So does a 2.5 MW/10 MWh standalone battery installed in 2025 at a substation in a congested part of Connexus’s grid. The system boosts reliability in the area without requiring a larger transformer, saving members money and avoiding a disruptive upgrade process, Connexus says.

And because it’s registered with MISO as a capacity asset, the battery system “can capture additional wholesale market value streams through accredited capacity and strategic dispatch during high price periods,” Haagenson said.

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 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.

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.

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 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.

The PJM Interconnection on May 6 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. 

The North American Electric Reliability Corp. on May 4 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 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.