Energy Resilience

Much of the upfront cost of installing a battery energy storage system is the same whether you put in a four-hour battery or an eight-hour battery. So if you envision using a BESS system for time-of-use energy arbitrage as well as for backup power, it might make sense to go with a bigger battery, a battery executive says. 

“If you install a 100 kilowatt-Hour battery … you still have all the [installation costs]” of a larger battery, Scott Childers, vice president of essential power at Stryten Energy, said in an interview. “If you install a 1 megawatt-Hour battery, you’ve spread those costs across a lot more hours, so in terms of the battery itself, it’s almost linear [whether] it’s a $100 battery [or] a $200 battery. There are definitely economies of scale.”

Manufacturing facilities have used battery energy storage systems for years to ensure they have power to maintain operations during blackouts and to cut utility pricing premiums during peak load periods, but today more facilities are looking at the systems as energy volatility increases and the costs of battery power drop. 

“Interest in battery energy storage systems (BESS) has accelerated,” says Matthew Keever, director of onsite solar for North America at World Kinect.  

U.S. battery demand for stationary storage systems jumped by 29% in 2025, according to data from the Solar Energy Industries Association, or SEIA. This year, U.S. BESS deployments are set to increase to 70 GWh/35GW, from 57GWh/28 GW in 2025, according to an SEIA report prepared by Benchmark Minerals. 

Facilities can typically manage against blackout risk if they can draw on four hours of backup power when needed, but that doesn’t mean they have to ensure four hours of charge at all times, said Childers. “Most power outages are less than four hours,” he said. “So you’re going to cover 90%-plus of your risk scenarios by having a battery that’s four hours or greater in that location. But if you want a combination of both backup power and energy arbitrage, you’ve only got to save some of the charge for backup.”

For many facilities, a four-hour battery is probably sufficient, he said. In most scenarios, the facility can get away with discharging half of the battery storage for energy arbitrage during the day, when utility rates are highest, and then charge the battery back up to four hours at night, when rates tend to be lowest.

“It’s a little bit of a numbers game in terms of when an energy event will happen and when you’ll be using that discharge,” he said. “You can definitely play in that gray zone…. The worst-case scenario is, if you’re half discharged and you end up with an emergency event, you only have two hours of use of that battery instead of four.”

But even in that case, the likelihood is high that two hours of charge will be enough, he said. “Per the math, you have a really high probability you’re going to ride out that blackout,” he said. 

Even so, it can make sense to install more capacity, whether it’s a five-hour or an eight-hour battery, because of the fixed upfront costs regardless of the battery size, he said. 

“A lot of the costs that you experience when installing a battery are actually not the battery,” he said. “It’s all the installation. It’s a capital project. ... There’s concrete involved. There’s permitting and inspectors that have to take their time to issue [permits].”

Different batteries, different benefits

Traditional lead batteries are ideal for covering blackouts because they don’t require any digital support, he said. They can be stored inside the facility, and they kick in instantly when the grid goes down. “You won’t even know that the grid dropped because the battery will pick it up that fast,” Childers said. 

They’re limited in their duration, though. Depending on the size of the battery, it won’t go beyond a few hours. For longer blackouts, facilities can better manage risk with a vanadium redox flow battery, or VRFB. “It’s excellent at long duration,” he said. “It can go days and beyond what a lead battery can survive.”

But they have their own limitations. VRFBs generate power by pumping an electrolyte solution, so they require their own separate power source to pump the liquid as needed. 

“If you don’t need the vanadium flow battery, you would turn those pumps off, because they become a parasitic load,” he said. [But] if you turn it off completely, it takes a few minutes for those pumps to turn on and get the circulation of the electrolytes up and moving. It probably takes as much as 10 seconds to 30 seconds.”

In an electrical environment, even a delay as short as 10 seconds can be devastating, he said, because it can harm the variable frequency drives, or VFDs, and other components that are critical to equipment. “Those devices can be really sensitive,” he said. “You might blow four or five of your VFDs in one plant in one blackout event just from that surge.”

A good combination is a vanadium flow battery with a lead battery as support, he said. 

“A perfect idea for hybridization is to take a passive lead device and put it in front of a vanadium flow battery,” he said. “You get the best of all worlds. You get a jump start from blackout conditions. You get parasitic load elimination from the vanadium flow battery, and you get the long duration.”

Lithium batteries are a third option, although those can come with safety issues that affect how they’re managed and stored. 

“Each one has a specific application use that’s unique to it,” he said. “You can’t solve all of the energy scenarios with one chemistry.” 

These three, by themselves or in some combination, would probably cover 90% of the scenarios for a typical facility, Childers said. 

“These are the most technology-ready, cost-effective and fitting most of the applications,” he said.

As fires raged across the Los Angeles region in January, regional electric utility Southern California Edison cut power to more than 360,000 customers. Some remained without service for weeks.

The event was one of dozens of public safety power shutoffs tracked by California’s public utility regulator over the past year. Power lines are more prone to failure in hot, windy weather, sometimes sparking fires that quickly burn out of control, the California Public Utilities Commission says. Electric companies deenergize them to reduce the risk of devastating events like 2018’s Camp Fire, which killed 85 people and pushed Northern California utility Pacific Gas and Electric into bankruptcy. 

“Any time you get hot weather and winds, you’re going to see PSPS events,” said Marc Starkey, a California-based account executive in Schneider Electric’s sustainability business. Some vulnerable areas see up to 10 PSPS events per year, he said. 

In response, municipal governments and school districts across California are setting up microgrids that enable them to maintain critical infrastructure and services using locally produced power. Ojai Unified School District, for example, tapped Schneider to deploy a microgrid powered primarily by solar panels and batteries. The project will provide backup power for a school facility that is a designated evacuation site and served as a Red Cross shelter after a 2017 wildfire.

But as Republicans in Congress push through a budget reconciliation bill that could remove key federal backing for clean energy resources, local resilience efforts, like those from Ojai’s school district, face an uncertain and potentially more expensive future, Starkey said. 

Financial threats and opportunities for microgrid customers

As passed by the House, the reconciliation bill would effectively eliminate clean energy tax credits worth 30% or more of qualified investments in projects that begin construction 60 days after it’s signed into law. President Trump supports the bill and has said he wants Congress to pass it by July 4. Though some lawmakers are skeptical about hitting that deadline, Schneider isn’t taking any chances, Starkey said.

“Our strategy is … you have to have your project in construction in September to qualify for the investment tax credit,” Starkey said. “As we’re getting customers under contract, if we can procure solar panels well in advance of the design being finalized and in construction, we do that.”

For now, tax-exempt entities like city governments and school districts can tap those federal tax credits using the “direct pay” framework created by the Inflation Reduction Act of 2022.

The GOP budget would also rescind billions in clean energy funding authorized by the Inflation Reduction Act, which provides loan guarantees and grants to microgrid projects in California and elsewhere across the U.S.. 

The good news for municipalities, school districts and other facility operators interested in microgrids is that they can often turn to state or local grants, utility rebates and other low-cost financing. 

That’s on top of the potentially significant utility bill savings from powering regular operations with on-site solar and batteries, which Schneider can then leverage in longer-term structured performance contracts, Starkey said. 

Also known as energy savings performance contracts and often involving energy-efficient upgrades like LED lighting, new HVAC and digital building controls, those contract arrangements help mitigate the upfront costs of major energy-related upgrades and insulate customers from future utility rate hikes, the U.S. Department of Energy says. 

ESPC customers generally own their energy systems, allowing them to depreciate the investment over time. Energy-as-a-service agreements, or EaaS, offer a turnkey alternative for customers not interested in financing and maintaining the infrastructure themselves. 

Most Schneider customers prefer direct ownership, which is fine with the company — but it’s also willing to work with those that just want to buy power generated on-site, Starkey said. 

Schneider offers two EaaS solutions, AlphaStruxure and GreenStruxure, in partnership with private equity firms Carlyle Group and Blackstone. The average AlphaStruxure customer requires more than 5 megawatts of power, the equivalent of 5,000 typical homes, while GreenStruxure is a zero-carbon solution for commercial and industrial customers that spend at least $500,000 per year on electricity, Schneider says.

Keeping the lights on when it really matters

Beyond direct financial savings, microgrids have indirect benefits like fewer operational disruptions, Starkey said. Some PSPS events anticipate actual wildfire emergencies, as in Los Angeles this winter, but many do not. Without reliable, backup power, schools and municipal service providers may need to close or curtail activities during longer shutdowns.

“[Our customers] are saying, ‘Hey, we want to keep our students in school,’” Starkey said.

Because states fund schools based on average daily attendance, extended or repeated closures may result in significantly less revenue over the course of a school year, Starkey said. And in an actual emergency — or even abnormally hot weather, when schools and other municipal facilities may double as cooling centers — backup power is critical to ensure vulnerable residents have a safe place to go, he said.

Most microgrids combine renewable energy sources like solar panels with fossil-fuel generators and batteries for backup power, Schneider says. But Starkey said it’s easy enough to tailor the mix of power sources to the needs of a particular site or user, including those with strict emissions-reduction goals.

“We definitely want to meet the vision of the customer in terms of their sustainability and climate action goals,” he said. Schneider’s solar-powered parking shelters and two-way “vehicle-to-grid” ports support the growing number of California customers that need to run electric fleet vehicles — or use them as mobile backup batteries — when the grid is down.

On the other hand, some customers already have diesel generators and want to be able to plug them into new microgrids. Schneider’s microgrid at the Ojai Unified School District offers this flexibility, Starkey said. Solar-and-battery combos can provide reliable backup power for relatively long periods in sunny California, but customers with mission-critical needs generally want to have generators on hand for added resilience in multiday outages, he said.

Regardless of their sustainability or technology preferences, Starkey tells facility operators to spend time on the front end figuring out which systems and functions truly need to be backed up. A municipal customer might go into a project expecting to back up its entire civic center, then consult with someone like Starkey and settle on a smaller system to serve just critical functions like IT and public works, he said.

Realistic outage duration and frequency projections are important too, Starkey said. In areas not prone to long PSPS events or general grid unreliability, that exercise keeps costs in check without compromising performance.

“The last thing we want to do is spend a bunch of money oversizing a solar and battery system to last for days when really you need [one] a fraction of that size,” Starkey said.

Battery-power startup Form Energy’s announcement earlier this month that it secured a $750 million capital infusion could signal a step forward in the commercialization of low-cost, long-duration energy storage.

The company produces an iron-air battery that it says can discharge more than 100 hours of power before needing to recharge, expanding options for facilities trying to optimize on-site energy systems. A facility that uses on-site solar to meet part of its power needs, for example, can use the batteries to cover extended periods of insufficient sunlight to keep the system generating power.   

But the real value would be its low cost, says Christopher Rahn, a professor of mechanical engineering at Pennsylvania State University. 

“You can make any battery system discharge more slowly,” Rahn told Facilities Dive in an interview. “But I think what is important is cost, and that’s dollars per kilowatt hour, especially for this [stationary on-site] application, where they’re not as worried about how big it is or how heavy it is. They’re really worried about cost.”

A TechCrunch analysis of a $1 billion project that Form Energy is working on with Google and regional utility Xcel Energy to produce 30 gigawatt-hours of battery energy at a data center in Minnesota suggests the all-in capital cost for the batteries is approximately $33.33 per kilowatt-hour. Form Energy said five years ago that it expects the cost to drop to $20 per kWh.

At those cost levels, there’s an economic case for the batteries, Rahn said. 

“The numbers I’ve seen for lithium-ion in a packaged form is around $100 per kWh,” he said. If Form Energy can offer a battery that discharges at $50 per kWh, “that could really be competitive. That means for that same application, to get 100 hours of energy you could spend $100 per kWh and do lithium-ion or you could spend $50, half as much, and get the same performance for that very slow discharge rate.”

Physical scale could be an issue, though, he said. “If you want to do, say, 10 kW for 100 hours, then you need a lot of capacity,” he said. “You need a lot of batteries.”

Iron-air batteries have also been known to offer lower efficiency over their lifetime, partly because of the release of hydrogen gas during battery discharge, according to research published in Renewable and Sustainable Energy Reviews. Their round-trip efficiency of 40% to 50% means that for every 10 MWh of energy stored, only 4-5 MWh are returned on discharge, Energy Digital reported.

The project that Form Energy is working on with Google and Xcel, to help power one of the tech giant’s data centers, in Pine Island, Minnesota, would be the world’s largest battery.  

“The new plant in Minnesota will be big enough to deliver 300 megawatts of power and store an enormous 30 gigawatt-hours of energy, making it the largest battery by capacity that’s been announced so far,” a Fast Company article says. “By comparison, that’s more storage than all of the battery projects built in the U.S. in 2024 added together.”

The Google-funded battery plant would help Xcel cover new demand created by the data center by providing 1,900 MW of new clean energy: 1,400 MW from wind, 200 MW from solar and 300 MW from the battery system.

The battery component, Xcel said in a statement when announcing the project, will help it from a resilience standpoint, “providing firm capacity and strengthening grid reliability when it is needed most, even over multiple days.”

Iron-air batteries are sometimes referred to as rust batteries because they convert the natural rusting process of iron metal into energy using what’s called reversible rusting. As air enters into a battery cell containing an electrolyte and iron and air electrodes, oxygen converts the iron metal into rust, releasing energy. When an electrical current is introduced into the cell, the rust converts back to iron, releasing oxygen and storing energy. Repeating the process creates a durable source of energy, according to a Form Energy information page.

The company’s $750 million infusion brings its total capital raised to $2 billion since it launched in 2017, giving it the resources to scale up its manufacturing facility, located in Weirton, West Virginia. “Proceeds … will be used to accelerate Form Energy’s manufacturing scale-up,” the company said.  

Including the Google-Xcel project, the company has an 80 gigawatt-hour order backlog that it aims to tackle with the new resources. Two other big projects on backlog are from AI infrastructure company Crusoe and renewable energy company FuturEnergy Ireland. “These agreements underscore the growing role of multi-day energy storage in supporting rising electricity demand,” Form Energy said in a statement.

Microgrids don't pose an immediate threat to diesel generators as the way most managers ensure their facilities have backup power, but Allan Schurr, the chief commercial officer at microgrid company Enchanted Rock, expects more operators to look at what he says is a cleaner, administratively easier approach that microgrids offer. 

“Diesel generators are in short supply and sometimes it's two years before you can get a diesel generator delivered,” Schurr told Facilities Dive. “By having a microgrid … you can [have something] more reliable and cleaner” and have it up and running within a year.”

A microgrid is a self-contained electrical network that companies like Schurr’s install on their client’s property. Enchanted Rock builds its network using half-megawatt natural gas generators that it gangs together based on the amount of load the client wants to back up. For a hospital, it might be a network of 10 generators. For a grocery store, it might be two or three. 

“Our standardization of equipment is part of our differentiator,” said Schurr, referring to his company’s use of a single-size generator. “That allows us to dial in exactly the amount of backup power that's needed for any facility size.”

Power from the microgrid is cleaner, Schurr says. In the case of Enchanted Rock, it’s cleaner because it’s generated from natural gas. But microgrids can also use solar, wind and other non-fossil-fuel burning sources. 

The cleaner power might be important to organizations that make sustainability a priority but it can also help lower energy costs by enabling the microgrid to run power outside of emergency situations and sell it as a supplemental power source to the local utility grid. That revenue goes to the microgrid and helps offset what the property owner pays for its backup power. 

“So, [our clients] can get the air permits to operate in nonemergency hours, and that's where the cash register comes in,” Schurr said. “If you can operate outside of emergencies, you can get paid by the grid to run during certain critical peak hours, and those payments offset the cost of the resiliency function.”

Avoiding test disruptions

Having the power run alongside the grid also solves one of the biggest headaches facilities managers deal with when they have a backup generator, Schurr said: the annual test. 

In the typical case, the operator can start up the generator only after first shutting down the regular power, disrupting work for about 10 seconds at the start of the test and then again at the end, during which gaps there’s no power flowing to the facility. 

“All the tenants in that building, whoever they might be, experience that first little outage, and then when you go back onto grid power, you take another outage before you connect to the grid again,” he said. 

To avoid the disruption, some operators conduct the test without transferring the load to the generator. By doing that, they can get assurances the generator works but not whether it can carry the load that would be needed if there’s a power loss. 

“They just start up the generator and it idles,” he said.  “‘Started. Worked. We're good.’”

Some operators get around the disruption by testing the generator on a simulated load. “You bring in what's known as a load bank, which is literally like a giant toaster,” he said. “It creates a load for you to test,” but it’s expensive.

The other alternative is not to test at all. That’s not an option for hospitals and other regulated facilities that require annual testing to ensure continuous power to critical infrastructure. But for other facilities, the annual test rarely survives a budget cut. 

“Those service contracts are one of the first things that get deferred,” he said. “Facility managers know this well. They never have the budget to do what they want to do, and so they're always looking for ways of stretching their O&M dollars, [which could yield] the kind of slippery slope that is a lack of reliability.”

One-year installation

Diesel generators are in short supply right now, so Schurr sees an opening for companies like his. Rather than wait two years to get a generator installed, operators can get backup power within a year. That’s about what it takes to get the network built out on the client’s property and tie the network into the local utility grid. 

“One of the critical path items is getting the gas interconnect from the local gas utility,” he said. “So, we order the equipment for the electric switch gear, the gas interconnection and then we do permitting and construction. And usually within a year, we can be completed and operational.”

Separate from providing the property on which to build the grid, the client pays a set-up fee to do the construction work and install the network and then a monthly service fee – basically, a subscription – to have the company maintain and operate the microgrid. 

“They get the full gamut of the maintenance and operation inside of that fee unless there's an outage, and then they pay fuel during that outage,” he said. 

Enchanted Rock typically owns the microgrid and therefore owns any revenue it generates from selling surplus power to the local grid, which helps keep down the service fee to the client. In some cases, the client elects to own the microgrid, making it the seller of the surplus power.  

Schurr touts this resiliency-as-a-service model as a way to make backup power generation economically feasible for organizations that might otherwise hesitate to invest in it. 

“We have grocery stores that want to be there for their customers when there's an emergency,” he said. “They don't want to close down. They don't want to throw out all the food. They want to be open for business. So, we have customers in a lot of different industries that are trying to serve their customers better. And by so doing, they think that the business case is very strong.”

As global leaders gathered in Davos, the story that dominated the World Economic Forum was familiar: artificial intelligence is the next great engine of productivity, competitiveness, and economic growth. “Industries in the Intelligent Age” was one of the key themes this year.

But we are not paying enough attention to the less glamorous reality underneath it: the physical infrastructure required to make AI work. We can build the world’s best models, write the world’s best code and design the world’s fastest chips. But none of it matters if we cannot power the data centers. And today, the electrical grid cannot scale fast enough to support the pace of AI-driven demand without consequences for reliability and affordability.  

U.S. data center grid power demand was forecasted to rise 22% in 2025 and nearly triple by 2030, driven largely by AI workloads, straining existing grid capacity. In fact, America’s largest power-grid operator, PJM Interconnection, is being pushed to the brink by surging demand from data centers, with generation capacity at risk of maxing out during extreme weather and consumer anger rising as rates increase. The next question is what we do about it.

If we handle the AI boom the wrong way, we will put grid stability and public trust at odds with tech-led growth. If we handle it the right way, we can accelerate AI competitiveness without turning household electricity bills into collateral damage.  

In the coming years, more large data center developers will reach the same conclusion: they cannot rely on the grid alone. They will have to bring their own power. AI workloads require enormous compute capacity. That means more servers, more cooling and far higher electricity consumption.  

We are essentially building a new electricity-intensive industry in real time, yet our grid is still operating under assumptions built for a different era. Across the U.S., utilities and grid operators are warning that demand is rising faster than expected. Transmission and interconnection queues are growing. Even when generation is available, getting power to the right place at the right time has become a bottleneck.  

For most Americans, resilience is something we notice only when it fails. But for a hyperscale data center, a power interruption is lost revenue, disrupted customers, damaged equipment and reputational risk. If you are investing billions of dollars in a facility that must operate around the clock, the answer is not to hope the grid catches up. The answer is to design for resilience.

This leads to an uncomfortable truth: The power system cannot meet every new load on the timeline the AI economy is demanding. This is not about blame. Utilities are working hard. Regulators are moving faster than before. But even with the best intentions, expanding and modernizing the grid takes time. Permitting, transmission planning, materials constraints and workforce availability do not disappear simply because demand is urgent.  

In the meantime, placing massive new electrical loads onto an already strained system risks everyone. If large customers treat the grid as unlimited and immediate, ratepayers will feel the consequences. That is why the next phase of American AI competitiveness must include a new operating model where the grid is a partner. A data center of the future will not look like a traditional building with a utility line feeding it. It will look more like a self-contained energy ecosystem.  

That model already exists in other parts of the economy. Hospitals, military bases, emergency shelters and critical government facilities do not operate under the assumption that outside power will always be available. They build redundancy. They invest in backup generation. They deploy microgrids. They plan for disruption.  

Data centers should be treated the same way because increasingly they perform critical functions for society and the economy. The difference now is scale. Some of these investments will be driven by economics. Others will be driven by reliability requirements and customer expectations. In Washington, policymakers speak often about winning the AI race.  

That goal requires realism, and, more importantly, energy. It is the foundation. If the U.S. fails to expand power infrastructure fast enough, we risk turning an AI boom into a self-inflicted constraint. We will delay projects. We will push investment to other regions. We will raise costs. And we will weaken resilience at the exact moment we need it most.  

That means modernizing the grid. It means accelerating new generation and storage. It means reforming permitting and interconnection timelines. And it means acknowledging that large energy customers will need to invest directly in resilience.   

Developers and operators are increasingly exploring behind-the-meter power solutions because they understand what is at stake. The future requires a partnership model where the grid provides connectivity and market coordination, while large customers bring distributed resiliency and flexibility.  

The grid cannot do this alone. So the most reliable data centers of the future, the ones that protect uptime, control costs and support national competitiveness, will not just plug in. They will bring their own power.  

The constraint on the electricity grid is pushing an increasing number of facility managers to look at behind-the-meter energy strategies, a trend that could play to the strengths of microturbine provider Capstone Energy+, the company’s CEO says in an interview with Facilities Dive. 

The bearings in the company’s microturbines ride on a cushion of air rather than lubricants, eliminating the friction that’s the main source of noise and emissions in gas engines, Capstone Energy+ CEO Vince Canino said. 

“There are no lubricants, no oil, no coolants,” said Canino, who joined the company in 2024 after holding executive positions at GE and Trane, among other companies. “That also helps us provide some of the lowest emissions technology out there.”

Noise and emissions from power generation are a big part of the pushback against data centers, which are increasingly deploying their own power to help reduce demand on the local utility and in some cases to meet state bring-your-own-power mandates.  

Increasingly, facilities in all types of verticals, not just data centers, are looking at behind-the-meter solutions, Canino said. 

“We have an auto shredder recycling plant in Los Angeles where the utility couldn’t bring the power in for another 3-4 years, so they just decided they were going to build their own plant and not even connect to the grid,” he said. “We’re even in grocery stores — anywhere where a customer has an electricity demand or thermal demand.”

Working around utilities’ capacity constraints is a big reason companies are deploying their own power, but they’re also executing on energy resilience and carbon-reduction strategies, he said.  

“Facilities are starting to see the risk, and they need resiliency and more of a sustainable lower carbon footprint solution,” he said. 

Capstone launched in the late 1980s offering microturbines as range extenders for hybrid cars and buses before pivoting about a decade later to stationary engines. It completed a financial restructuring in 2023 and on July 8, after a three-year hiatus, resumed trading on Nasdaq. 

“There was a lot of hard work,” Canino said. “There are a lot of people in this company that put the heartbeats in to make this happen.”

The company offers 30 kW, 65 kW and 200 kW engines. With the larger engine it takes a multi-bay approach, so facility managers that expect their needs to grow can deploy the engines in enclosures that have room for additional capacity. 

“Customers … say, ‘Well, I only need 600 kW today [but] I may need a megawatt in the next few years,’ so they’ll buy what we call the 5-bay enclosure. Two bays are empty, and then when they need that extra power, they just buy the engines. We ship them and install them for them.”

Microturbines have the advantage of being small. The company’s 65 kW engine is about the size of a refrigerator.  

“I was on the roof of the Riu Hotel” in New York City, Canino said. “We had six of these C65s lined up … providing electricity as well as hot water” with enough space to add more later. “That’s the kind of modularity that we have.” 

To accommodate facilities’ budget constraints and operational plans, the company makes its engines available for lease, purchase or lease-to-own, or it will retain ownership and sell the power under a power purchase or energy service agreement.  

Under these agreements, “the customer doesn’t really put anything to it,” he said. “They could if they want to … but typically they put very little out, and then they’re paying a capacity and an energy fee for electricity and whatever thermal that project may deliver.”

Canino sees the United States and other countries going through what he calls an energy renaissance, driven in part by the tension that’s increasing as the public sector pushes its agencies and the private sector to electrify at the same time that utilities are facing capacity constraints from the growth of data centers, electric vehicle charging and building electrification.  

“The obvious answer is, [utilities] have to build more power plants,” he said, but “building more power plants takes a long time.”

That gap in new power generation creates opportunities for solar, wind and battery power, but they require a lot of space and, with some exceptions, they’re not 24/7, he said, so there’s a place for microturbine technology. 

“It becomes a good solution, because it’s quiet, it’s clean, and it can be temporary, mobile or permanent,” he said.

AI data centers in the United States could consume 33.8 gigawatts of power by 2030, or about 3% of the country’s generating capacity, Schneider Electric said earlier this year. Some AI power demand projections are even more aggressive, like a 2024 RAND Corporation forecast cited by Schneider that sees 130 GW of data center demand in 2030.

With data center projects worth at least $64 billion delayed or blocked by local opposition and state policymakers and regulators placing restrictions on development, a backlash appears to be brewing. 

Data center opponents cite a litany of concerns, from noise to water pollution, but some of the most frequently cited center on the local impacts of onsite power generation and broader effects on the electric grid. Earlier this month, Elon Musk’s xAI overcame local opposition to secure an air permit for a fleet of gas generators at its AI training center in Memphis, Tenn. 

Texas lawmakers recently passed a law requiring new data centers to disconnect from the grid during periods of high power demand. Several states have implemented or are considering special utility tariffs requiring data center companies to cover the costs of grid upgrades they benefit from. North Carolina utility regulators plan a technical conference in October on data centers’ potential impacts on power reliability.

Data centers’ appetite for power and the growing recognition that unchecked growth would be a problem for the grid could cause short-term growing pains for the industry, said Kelcy Pegler, CEO of FlexGen, a battery management software company.

“From a societal perspective, we are underestimating the impact that data centers will have on the grid,” Pegler said in an interview. “We’re going to have a break-in period where data center ambitions will have trouble coming to fruition.”

Earlier this year, FlexGen partnered with electrical contractor Rosendin to develop and deploy a battery-based solution to help AI data centers operate more reliably with fewer impacts on nearby utility customers and the grid as a whole. Their solution could also lower data centers’ enormous power costs — which can reach 60% of operating expenses — while reducing fossil-fuel generator use, Pegler said.

Better power management with fewer grid impacts

FlexGen and Rosendin teamed up to keep AI data center operators ahead of an expected exponential increase in newer facilities’ power density that outstrips the capabilities of traditional uninterruptible power supply systems.

UPS systems integrate directly with individual server racks and respond near-instantaneously to power interruptions, protecting sensitive chips and networking equipment from damage. But the latest NVIDIA chips consume far more power than previous generations despite significant efficiency improvements, necessitating more powerful battery backup systems at the building or campus level, Pegler said.

“No one saw this coming because no one knew how [powerful] the new chip would be,” he said. 

That touched off a scramble among data center developers to find solutions for facilities in development today. Those facilities already look different than their predecessors because the latest chips generally need some form of liquid cooling, which rejects heat more effectively than forced air.

The FlexGen-Rosendin offering is “a smarter, leaner, and more responsive approach to data center energy design that doesn’t require any redesigns inside the walls of the data center,” FlexGen Chief Innovation Officer Pasi Taimela said last month.

The partnership combines Rosendin’s utility-scale “BESSUPS” battery backup system with FlexGen technology that allows data centers to transition smoothly between grid-connected and “island” modes, the companies say. Pegler said the solution is a key reliability backstop for data centers as real-time demand for AI inference rises in critical industries.

Today, “ChatGPT is willing to say, ‘Sorry, I can’t help you right now,’ but you can imagine a lot of future use cases” — like time-sensitive healthcare functions — “where ‘I can’t help you right now’ is not an option,” he said.

Flexible BESSUPS systems also position data centers to support rather than burden the grid with their at-times overwhelming demand for power, FlexGen and Rosendin say. During periods of high stress on the grid, such as hot summer evenings, facilities can run off their own batteries. Or, if they can afford to ramp down some computing processes, they can temporarily transform into power plants and dispatch the energy stored in those batteries to the grid. 

And even in non-emergency situations, data centers’ power demand can change rapidly in a matter of minutes, causing voltage fluctuations that can damage the sensitive computing systems onsite and unrelated commercial and consumer equipment nearby. A Wood Mackenzie analysis last month saw power consumption at one hyperscale data center drop by 30% in five minutes after spiking nearly as fast, for example.

Data centers’ BESSUPS systems can smooth out these sometimes “violent” voltage variations and protect sensitive equipment, like utility-scale battery systems do on the main grid, Pegler said. 

Bridging the grid connection gap

FlexGen and Rosendin are teaming up to provide one option in a broad set of complementary onsite power solutions for data centers facing grid constraints, experts say. Other options include onsite gas generators, batteries and solar panels — or some combination thereof — as “bridging” the potentially five- to seven-year gap between interconnection request and final approval for a 1-GW hyperscale data campus, says Jim Grice, chair of the data centers and digital infrastructure practice at the law firm Akerman. 

The buildout of a hyperscale data campus doesn’t happen all at once, Grice said in an interview. A typical hyperscale campus might start at 100 to 200 megawatts and then scale to 1 GW over time, he said, ideally after the grid connection comes through. At that point, the “bridge” power infrastructure can transition into a backup role and — like FlexGen and Rosendin envision — potentially act as a self-contained microgrid when grid demand peaks. 

But while the “bridge” doesn’t have to power the entire site at full buildout, it does have to be as resilient as a grid connection plus onsite backup power and not cost multiple times more, Grice said.

“You basically have to overprovision your power capacity, and that is going to have an impact on pricing,” he said. “It’s like 3-D chess.”

The need for redundancy has some developers racing to acquire and stockpile gas-fired generators, but order queues even for smaller generators — and not just the larger turbines booked out to the end of the decade — now stretch out for years in some cases, Grice said. Developers able to source gas generators sooner, like the group behind a $10 billion Pennsylvania power project that aims to begin operating next year, have openly touted their plans.

Keeping sustainability goals within reach

For rural data center campuses with fewer space constraints, onsite renewable energy may offer faster “time to power” than gas, Grice said. Google announced last year that it would locate data centers near and buy power from up to $20 billion of sustainably powered “energy parks” developed by Intersect Power, the first of which could come online next year. The catch is that onsite renewables require more space than gas generators — about six to eight acres per megawatt of solar capacity, Grice said.

Despite that, and despite policy headwinds for renewable energy at the federal level, most data center companies prefer clean power if at all possible, Grice said. 

“All things being equal, if there’s a site available with solar plus batteries and grid backup, [a data center would] select that over connecting to a grid powered mostly by coal,” Grice said. “We’re seeing all sorts of [data center] development strategies with large-scale renewables — that is very much a market trend that’s happening.” 

That may be why some data center companies are bullish on novel energy storage technologies that could satisfy their high uptime requirements while further reducing reliance on fossil-fueled power from onsite generators or the power grid itself.

Prometheus Hyperscale announced in May that it would add organic flow batteries from XL Batteries in phases at a Wyoming data center. First up is a small pilot project, set for 2027, to validate the technology’s capabilities. If the pilot goes well, two systems capable of discharging 12.5 MW per hour for 10 hours would follow in 2028 and 2029, the companies say.

Unlike today’s dominant lithium-ion chemistry, organic flow batteries’ active materials are non-toxic, non-flammable and non-corrosive, making them safer to place near multi-billion-dollar data centers. (Prometheus will also bury its batteries so they perform better in the harsh Wyoming climate, senior energy advisor Adam Mirick said in an interview.)

Additionally, flow batteries can more economically sustain maximum discharge rates over longer periods of time than lithium-ion batteries. That means they can more reliably power data centers with stored energy from the wind, sun and other low-emissions sources — including, potentially, the small nuclear reactors Prometheus and some other data center companies hope to power their facilities in the future.

“If this does work, and we think it will, that gives us a line of sight to acquire and begin to incorporate [flow batteries] into future data centers,” Mirick said. 

Heating, ventilation, air-conditioning and refrigerant professionals are looking ahead at the work to be done this year, and energy resilience is at the top of the list.  

“ASHRAE has been providing leadership and guidance in energy efficiency, indoor air quality and carbon emissions reduction,” the organization’s new president, Sarah Maston, said in her inaugural address at the 2026 ASHRAE conference. “So, where do we go from here?”

Maston said her aim is to focus the organization on resilience — how the facilities profession can work together to develop game plans to improve the efficiency, performance and resilience of buildings in the face of climate and infrastructure challenges.

“Everyone needs to dig deep to meet the trials ahead,” said Maston, director of commissioning and energy services at Colliers Project Leaders. “Embrace the challenge and change the game…. We want everyone to get in the game.” 

Lessons learned

At the conference, attendees shared best practices that they’ve learned over the past year, which focused on indoor environmental quality under 2025-26 President Bill McQuade. 

Researchers at the Pacific Northwest National Laboratory, for example, held a workshop on how to achieve healthier buildings with lower cost and energy use. PNNL researchers Gabe Arnold, Meghan McNulty and Cary Faulkner shared data on the real-world costs of installing and using ventilation and air-cleaning strategies in classrooms to improve indoor air quality, and they provided guidance to help school districts choose building upgrades. 

As part of a new course offering ASHRAE Learning Institute credits, David Schurk, a Distinguished Lecturer and Instructor for the ASHRAE Learning Institute, taught participants concepts for “demystifying dehumidification” and providing ways to design high-performance moisture control systems. The course discussed psychrometry, the field of science and engineering that studies the behavior of moist air, and reviewed findings from ASHRAE research on damp buildings and human health.

Schurk explained that, by using a psychometric chart, HVAC professionals can determine what actions to take to reach an optimal temperature and relative humidity level. As with a road map, “connecting dots tells me where I need to go, how I need to get there [and] how many gallons of gas I need to use to make the trip,” he said. “If I plot one point and then plot another and connect the dots, I can size the system. You get the dots in the right place to start with, then you make the calculations and then you apply the equipment that will meet the needs.” 

In another session, experts from the University of Texas at Austin and Austin Energy discussed ways the City of Austin’s municipal utility and the university have embraced thermal energy storage, or TES, to reduce peak electric demand and meet air-conditioning needs for more than 55,000 students. By installing TES in its district cooling system and incentivizing customers to install storage in their facilities and adding price-driven chiller automated controls, operators were able to minimize demand charges and maximize the load shifted to low-cost periods. 

The approach the university took provides a secure and reliable framework for optimizing thermal networks, said Whitney Moyer, industrial automation specialist at Austin Energy. “The program [used] 55% less energy within this non-charge window than the operator today,” Moyer said. He underscored that these interventions can not only reduce capital expenditures by eliminating the need for high-cost chiller compressor variable frequency drives, but also limit the need for operators to be directly involved in plant operations. 

“This frees up their time,” Moyer said. “Being in a hybrid role is really the way going forward in our plans, because more and more of this is going to be automated away,” he said. “The more we do in-house, the cheaper it is.”