Energy Storage

Nearly every night for the first two weeks of July, Puerto Rico’s grid operator called on tens of thousands of batteries scattered across the island to overcome energy shortfalls and help deliver power to approximately three million residents — and it worked. 

What started as a modest pilot program in 2023 has grown into the first operational behind-the-meter virtual power plant in Latin America and the Caribbean, and a crucial support for the territory’s dilapidated energy infrastructure, said Javier Rúa-Jovet, chief policy officer of the Solar and Energy Storage Association of Puerto Rico.

“It’s grown … in the blink of an eye,” he said. “It’s something to be proud of.”

In May, Puerto Rico’s Energy Bureau, which regulates utilities, approved an emergency expansion of the “customer battery energy sharing” program in anticipation of a projected generation shortfall during the warmer months. 

Since then, LUMA Energy, the grid operator, celebrated what it called a “major energy milestone.”

“[L]ast night we successfully dispatched approximately 70,000 batteries, contributing around 48 MW of energy to the grid,” the company said in a July 9 statement posted on X.

“This collaboration helped address a generation shortfall of nearly 50 MW, assisting in preventing multiple load shedding events and keeping the lights on longer in many communities across the island,” it said.

Before Hurricanes Irma and Maria devastated Puerto Rico in 2017, the island had a modest solar industry, driven largely by the desire to save money on power bills through net metering, and “storage was not a thing,” Rúa-Jovet said.

What followed the deadly storms was the longest blackout in American history.

“That kind of shifted, in people’s minds, the thinking on energy and the value of resiliency, and the importance of just basic energy,” Rúa-Jovet said.

The Puerto Rico Energy Public Policy Act of 2019 codified the role of solar and storage in the island’s energy system and set a 100% renewable energy target by 2050, with interim targets on the way. 

Today, Rúa-Jovet said there are about 175,000 households with solar, and at least 160,000 of those also have storage. Companies are installing thousands of systems a month. There is also a growing market for batteries that charge from the grid without panels, he said, but the organization doesn’t have data on that. 

The growth of solar and storage has been made possible in part by financing and lease options offered by companies like Sunnova and Sunrun, which allow many customers to pay a monthly bill that is commensurate with what they were paying the utility, he said. 

Sunrun said in a statement that it has begun dispatching more than 37,000 home batteries to support Puerto Rico’s grid, and that its dispatchable power capacity has increased more than tenfold since last summer. It said customers will earn a minimum of approximately $200 per battery for participating in the distributed power plant. They can choose to earn more by adjusting their battery settings to send more energy onto the grid, or they can earn less and keep more energy for personal backup, it added. 

“This is the clearest case, at a large scale, of residential solar and batteries keeping an electricity grid energized for everyone on the grid,” said Chris Rauscher, head of grid services and virtual power plants at Sunrun, in an interview. “This is not happening anywhere else in the world right now, and so Puerto Rico is really very much at the forefront of energy innovation.”

Even Puerto Rico’s Republican governor, Jenniffer González Colón, who alarmed some clean energy advocates with her early support for gas generation, appears to be shifting.

She recently came out in defense of keeping in place the island’s existing net-metering system, which advocates say is crucial for expanding solar and storage. Her position put her at odds with leaders at the Puerto Rico Electric Power Authority, who are seeking to add a fixed charge to net metering program participants. 

“Net metering is nothing more than an incentive for people to use — in this case — solar panels to help the system at times when they are not consuming from the grid but are instead producing their own energy,” the governor said. “I am on the record opposing charging someone just for connecting.”

The governor is also embroiled in a public fight with the parent company of the island’s LNG supplier over what she described as “hostile” tactics, including withholding supply over a payment dispute. The company, New Fortress Energy, says Puerto Rico owes more than $10 million in unpaid invoices and interest, the San Juan Daily Star reported. 

Rúa-Jovet said blackouts have become so routine that solar and storage are now a necessity in Puerto Rico and demand is unlikely to be slowed by changes in federal policy — some of which were enacted through the tax code, which has limited impact on the territory. 

“The only thing that is working consistently in Puerto Rico is solar and batteries,” he said.

As the eastern half of the United States baked under record heat in late June and electricity demand reached multi-year peaks, it looked like the grid might succumb. 

Grid operators and public officials scrambled to avoid a disaster, ordering generators to defer maintenance and customers to conserve energy. The PJM Interconnection served about 161 GW of load on June 24, its highest demand since 2011 and not far off its all-time high of 165.6 GW.

But aside from scattered outages caused by heat-damaged electrical delivery equipment in parts of the New York City area, Eastern U.S. grids largely weathered the heatwave. 

Grid experts — and at least one grid operator — say at least some of the credit goes to distributed energy resource aggregations and flexible loads dispatching at higher rates than ever before. Those “virtual” or distributed power plants helped keep the lights on as generator reserve margins plummeted.

“PJM said that demand response was essential,” Federal Energy Regulatory Commission Chair Mark Christie said in a June 30 press conference focused on the need for resource adequacy amid rising load forecasts. “That 161-GW peak would have been higher without DR, so DR is an important part of the mix too.”

Major virtual power plant operators matched near-record peak loads with unprecedented dispatch activity. Sunrun dispatched more than 340 MW from customer-sited batteries on the evening of June 24. The same day, EnergyHub shed 900 MW of peak load and shifted 3.5 GWh of energy away from the highest-demand periods. Uplight managed about 350 MW of flexible load in 45 dispatch events across 16 utility programs over the course of the heat dome week. 

Supportive state policy, expectations for rising power demand and simple economics are pushing once-skeptical utilities to embrace VPPs, said Hannah Bascom, chief growth officer at Uplight.

“You're seeing [utility] folks on the supply side saying, ‘Wait, how many megawatts do we have lying around?’ And the light bulbs are starting to go off,” Bascom said in an interview.

Quicker and cheaper than traditional generation

It helps that it costs far less — and takes less time — to aggregate existing customer-sited resources than it does to build new dispatchable generation or storage, Bascom added. 

A new, 400-MW VPP has a net cost of $43/kW-year, compared with $69/kW-year for a utility-scale battery and $99/kW-year for a gas-fired peaker plant, the U.S. Department of Energy said in a January update to its virtual power plant liftoff report. An RMI report released last July said VPPs could be deployed in six to 12 months, quicker than any form of utility-scale generation. 

RMI’s report made a point of saying utilities eyeing VPPs in mid-2024 could have them ready in time for this summer’s heat. 

It’s clear many utilities and other load-serving entities have launched or expanded VPP offerings recently, said Kevin Brehm, a manager in RMI’s carbon-free electricity practice. 

“We’re definitely seeing progress in terms of the number of utility [VPP] programs, and in regulation and policy being implemented to advance VPPs,” he said in an interview.

Last year, RMI and the VPP Partnership published a flipbook featuring 75 U.S. VPPs with 3.9 million enrolled customers and 1.5 GW of capacity. That’s a small fraction of DOE’s 30 GW estimate of total U.S. VPP capacity in 2024.

Brehm cautioned that because VPPs can be deployed so quickly, published figures may underestimate capacity and thus the potential for utilities and aggregators to dispatch it during extreme weather events.

“Actual VPP capacity is what ultimately determines the level of response,” he said. “And [public reports] don’t tell the whole story because there’s a lag.”

Residential smart thermostats are already central to hot-climate VPP programs like Arizona Public Service Cool Rewards, whose 140 MW of thermostat capacity accounted for most of the utility’s 190-MW VPP as of last September. They’ll become even more important as smart thermostat adoption increases from today’s relatively low levels, Brehm said.

Commercial and industrial participation has room to grow

But much of the country’s VPP capacity still comes from manual commercial and industrial demand response programs, where power-hungry facilities agree to curtail load during peak periods, Wood Mackenzie said last year in a report. Another report by Energy Systems Integration Group showed C&I enrollments in wholesale demand response programs ranging from 4% to 10% of total potential capacity in most grid operator territories.

“Given how much capacity prices have risen recently, we’re going to see a lot more [C&I] demand response, and the potential is on the [multi] gigawatt scale,” Brehm said.

With the notable exception of the California Independent System Operator’s territory, C&I demand response enrollment has recently flatlined or declined in most regions due to limited customer awareness, weak financial incentives and barriers to wholesale market participation, according to ESIG. 

Brehm is hopeful that better technology and program design will turn the tide. Some VPP operators, like Voltus and CPower, coordinate multiple customer-sited resources, rather than interrupting power at a facility’s meter and shutting down production lines, he said. During the June heatwave, CPower says it dispatched 18.5 GWh across 120 events in PJM, ISO-New England and the New York Independent System Operator’s territory.

Small and midsize commercial facilities can also provide meaningful support during extreme weather events, said Thomas Flynn, chief administrative officer and general counsel at Budderfly, a commercial energy management provider serving more than 7,000 restaurants, medical clinics, convenience stores, hotels, gyms and other commercial sites nationwide.

Budderfly activated its first VPP on June 1, just in time for the heatwave. Flynn said the initial deployment included capacity in PJM, ISO-New England and the Southwest Power Pool — all hit hard last month — as well as CAISO. Enrollment could expand to NYISO and the Electric Reliability Council of Texas soon.

“We ran events across all of our programs during the week of the heat dome, activating programs from coast to coast,” Flynn said. “The events went well.”

For now, Budderfly’s VPP mainly dispatches HVAC systems via smart thermostats, but Flynn said it will soon expand to include onsite refrigeration systems, lighting, rooftop solar, electric vehicle chargers and onsite battery storage.

Because Budderfly owns those resources, dispatch is simpler than for customer-owned equipment, Flynn said. For local utilities, that simplicity — and the fact that commercial sites generally have larger and more consistent power loads — means more reliable and predictable VPP capacity.  

“Utilities see this model as a more reliable and scalable solution for flexible load capacity, particularly in regions where traditional demand response has been underutilized,” Flynn said. Budderfly can target dispatch in grid nodes without big industrial customers to provide load flexibility on a larger scale, he added.

Like Budderfly, Sunrun generally owns customer-sited resources. Its rapidly growing arsenal of batteries allows it to play a meaningful role in responding to extreme weather events, said Chris Rauscher, its head of grid services.

“We’ve fully embraced a storage-first strategy over the last few years,” Rauscher said. “Nearly 70% of our new installations include battery storage, up from just 10% a few years ago.”

Republican attack on renewables could help VPPs

Despite the recent U-turn in federal policy around renewables, the Trump administration’s preference for dispatchable power and declaration of an energy emergency create an opening for distributed asset owners like Sunrun, Rauscher said.

“Dispatchable energy is a top priority for this administration, and critical for grid stability,” he said. 

At the same time, Rauscher added, utilities are waking up to the fact that they need more electrons as fast as possible. Sunrun operates 17 VPP programs across the U.S., including utility-run programs like ConnectedSolutions in the Northeast and state programs like Demand Side Grid Support in California.

“The narrative is shifting [and] utilities are starting to see VPPs not just as pilots, but as core infrastructure,” Rauscher said.

Uplight’s Bascom agreed. While the rollback of clean energy tax credits will likely slow the deployment of distributed energy resources, that will also make it more expensive to build utility-scale generation, likely netting out to a boost for VPPs, she said.

“We still haven’t hit mass-market penetration,” she said. “We think there’s a lot of opportunity to leverage these resources for way, way cheaper than any type of new generation.”

In August 2022, the Inflation Reduction Act was signed into law, unleashing a wave of optimism across the renewable energy sector. As someone who has spent over a decade in utility-scale development — working on more than a gigawatt of solar and hundreds of megawatts of battery energy storage projects — I saw firsthand how the IRA reshaped boardroom conversations, procurement strategies and financial modeling. For the first time, standalone storage had a stable federal foothold, and that unlocked momentum like we had never seen.

But now, with growing uncertainty about the IRA’s future amid political shifts, a sobering question looms over our industry: Can energy storage continue its pivotal role in decarbonizing the grid without federal support?

In my view — and based on what I see on the ground, in permitting meetings, and in request for proposal negotiations — the answer is unequivocally yes.

Storage was never just about subsidies

The idea that the IRA is the sole engine behind energy storage’s rise is a convenient but flawed narrative. Storage didn’t suddenly appear in 2022. It’s been a solution in search of a market for the last decade. What’s changed is the context around it — renewable penetration, aging grids, demand volatility and increasing grid interdependencies. All these conditions make storage essential, not optional.

Even before the IRA, I worked on projects in Texas and California that penciled out based on merchant revenue and avoided curtailment alone. One of my earliest storage projects in Texas never qualified for investment tax credit support, and yet the business case was strong enough due to energy arbitrage and ancillary services. The market need was — and still is — that compelling.

Grid realities are bigger than federal politics

The demand for flexible capacity is driven by physics, not policy. The more we add solar and wind to the grid, the more we need responsive, dispatchable capacity to match supply with demand. That doesn’t change if a tax credit disappears.

Take the California Independent System Operator, for example. In the summer of 2020, rolling blackouts sent a clear message: variable renewables alone can’t carry the reliability burden. Since then, energy storage has become central to California’s long-term resource planning. I was directly involved in a 200 MW/800 MWh project in Southern California where local authorities, fire marshals and utilities were aligned in making the project succeed — not because of IRA incentives, but because their grid needed it.

And in ERCOT? The grid might not even have a capacity market, but storage there thrives on volatility. We’ve seen pricing events where storage earns its entire year's revenue in a few hours.

State-level momentum isn’t slowing

Federal uncertainty doesn't mean the end of support. Many states are doubling down. California has mandated 5,000 MW of new storage. New York is targeting 6,000 MW by 2030. Even Midwestern states are writing storage into their integrated resource plans.

From a developer's perspective, this is where things get real. My teams work closely with cities, utilities and permitting bodies. When we walk into a room with stakeholders from a city like Carson, California, where I led permitting for a large-scale project, no one asks if the IRA will still be around. They ask, “How can we make sure this is safe, on time and resilient?”

Buyers are driving demand

Utilities are not the only buyers anymore. Corporate power purchase agreements, particularly from data center operators and large industrials, are pushing unprecedented demand for renewable-backed firm power. These companies — Google, Amazon, Meta — are not motivated by policy fluctuations. They have decarbonization mandates embedded in their business models and investor commitments.

I recently sat in a negotiation with a major commercial off-taker who was evaluating battery storage not just for energy optimization, but for backup during regional grid outages. That conversation had nothing to do with tax credits and everything to do with business continuity.

The technology has moved faster than policy

Another reason I’m optimistic? The storage tech curve is outpacing the policy cycle. In 2017, lithium ferrophosphate batteries were still emerging. Today, they dominate procurement due to safety, price and supply chain reliability. Meanwhile, technologies like iron-air, zinc-based and flow batteries are starting to reach utility-scale pilots. These are not science experiments — they are the future of long-duration, IRA or not.

In a recent cost model we ran, even with ITC removed, LFP-based systems with 4-hour duration still remained competitive with gas peakers in certain markets. This is not a fluke; it’s the result of scale, innovation and fierce global competition that continues to drive down costs.

National resilience demands storage

Beyond economics and policy, storage is increasingly seen as a national security asset. Wildfires, hurricanes, cyberattacks — our grid faces multifaceted risks. Energy storage is now being integrated into resilience hubs, emergency response infrastructure and even Department of Defense installations.

When we design projects today, we often model not just the return on investment but the "value of resilience." I remember a stakeholder meeting with a coastal California municipality where we discussed microgrid designs that could island a fire station and a school. Their funding came from the Federal Emergency Management Agency, not the IRA. Their motivation? Keeping people safe.

What developers and policymakers must do now

If IRA support weakens or disappears, here’s what we in the industry must do to keep storage momentum alive:

1. Push for stable state-level frameworks that offer certainty on interconnection, permitting, and compensation for services like frequency regulation and spinning reserve.
2. Standardize permitting and fire code compliance (e.g., NFPA 855) to reduce project delays. I’ve seen projects get delayed by more than six months just for unclear horn-strobe or setback requirements.
3. Educate local stakeholders — not just policymakers, but communities — about storage safety and benefits. The opposition isn’t always ideological; sometimes it’s fear of the unknown.
4. Diversify technology portfolios to prepare for shifts in supply chain and duration needs. Hybrid systems (solar+storage) are not one-size-fits-all anymore.

Let’s be clear. The IRA was a game-changer. It accelerated deals, de-risked financing and opened doors. But energy storage’s value proposition goes far beyond subsidies.

As someone who has negotiated land leases, engineering, procurement and construction contracts, and fire code variances; who has watched battery prices drop while managing permitting on railroad and port easements; and who has sat across from city officials, explaining why a battery site won’t catch fire — the one thing I can say is this: Storage is here to stay.

Whether the IRA lives on or not, the future grid needs flexibility, speed and stability. Energy storage offers all three. It’s not a policy bubble. It’s the backbone of America’s energy transition.

Flow batteries are not, strictly speaking, a new technology. Yet even with improvements to decrease the cost, the flow batteries have never really caught on — until, perhaps, recently.

Energy storage developer XL Batteries said in May that it had penned a contract to pilot a 333-kW organic flow battery at a data center owned by Wyoming-based Prometheus Hyperscale. And other energy storage companies, focused on other types of batteries, have made similar announcements in recent months. Eos Energy Enterprises, which produces zinc-based batteries, has entered talks with an unnamed, large-scale developer of data centers.

While data center operators remain interested in renewable energy — a strategy that will likely require some form of energy storage — that wasn't the primary reason why Prometheus decided to green-light XL Batteries' flow battery pilot, according to XL Batteries CEO Tom Sisto. Rather, the company was looking for a non-flammable technology that could react quickly to large shifts in power demand, and XL's organic flow batteries fit the bill.

Other industry leaders agree with Sisto: as a growing number of data centers look to acquire massive power supplies on short timelines, it could be opening a door for mature, but as-yet under-utilized energy storage technologies.

Most projects remain relatively small-scale pilots as data center operators and developers test new solutions, but XL Batteries already has ample buyers waiting in the wings should the Prometheus project — which is slated for completion in 2027 — perform as expected. Prometheus itself has already contracted to buy up to two 12.5 MW purchases, one each in 2028 and 2029, pending the pilot.

“Once this is shown to be working, we're probably already sold out,” Sisto said.

An appetite for innovation

Data centers have multiple, unique power needs that could lead them to new and underused forms of energy storage, according to Sam Allen, mission critical director for technical innovation in the global facilities group at Burns & McDonnell, an engineering and construction firm that has taken on several data center projects. While traditional, cloud-type data centers have more steady, predictable loads, AI-focused data centers can be subject to sudden, often significant load fluctuations that lead to more complicated power needs, Allen said.

Data centers, like other large infrastructure projects, have also run into permitting and interconnection barriers, which has prompted their operators to look for independent sources of power that are flexible and reliable in the face of inconsistent power needs, said Tisha Scroggin-Wicker, decarbonization director in the power group at Burns & McDonnell.

Lithium-ion batteries remain the most widely discussed solution in conversations between Burns & McDonnell and their data center clients, Scroggin-Wicker said. But alternatives like flow batteries are getting more attention, because they can support a high number of charge-discharge cycles with minimal performance degradation over time. This makes them particularly well-suited to applications where long-term durability and cycling capability are critical, and to sites that experience frequent and rapid load fluctuations, she said.

Nickel-zinc batteries are also attracting attention from data centers on account of their high power density, improved safety profile and environmental benefits. And supercapacitors could prove interesting given their ability to provide a very large amount of power, but for a short period of time, Scroggin-Wicker said.

“Ultimately, the industry is focused on solutions that balance speed to market, operational reliability and sustainability,” Allen said. “There's a clear appetite for innovation and for moving beyond any single technology when it helps future-proof their infrastructure and support broader energy goals.”

Use-case based decisions

While there is interest among data centers in behind-the-meter energy storage that could connect to the grid and participate in virtual power plant programs and the like, for the most part the data centers being built haven't gone this direction, Scroggin-Wicker said. Most of Burns & McDonnell's clients that have built onsite energy storage are pairing storage with dedicated generation in a bid to bring the data center online faster than is possible if a utility is involved, she said.

Burns & McDonnell has also seen data centers express an interest in buying and operating existing energy storage projects, regardless of the storage technology involved. Existing lithium-ion projects, flow batteries, compressed air energy storage and other forms of long-duration energy storage have all drawn attention. These technologies could give data center operators a greater ability to manage higher power densities, integrate more renewable energy and provide reliable, flexible power supply — all on a comparatively short timetable relative to connecting to the grid, Scroggin-Wicker said.

Yet it's not yet clear whether any specific energy storage technology will win over the majority of data centers.

Jason Abiecunas, executive vice president of business development at FlexGen, a software provider that supports energy storage systems, said that data centers have expressed interest in a wide range of storage technologies. That's not surprising given the data centers' unique operational needs, but that does require a company like FlexGen to adapt to a potentially more technology-agnostic energy storage landscape, he said.

But when it comes time to deploy an energy storage system, Abiecunas said, only a handful of new technologies have won out.

“What’s becoming more clear is that battery chemistry decisions are increasingly use-case driven,” he said. “For example, when energy storage is deployed to displace traditional generators or extend backup capabilities, we’re seeing a growing interest in long-duration chemistries.”

Sisto doubts that data centers have any real need for what the utility sector would consider long-duration energy storage. Like Abiecunas, the interest he has seen is primarily driven by specific use-cases — and the cost of owning and operating an energy storage project decreases when you cycle that energy storage system more frequently. Storage technologies with a 36-48 hour range are, in his opinion, most likely to win out with data center operators; seasonal or ultra-long energy storage technologies will not.

The challenge at the moment, Sisto said, is that many of the options currently of interest to data centers remain relatively unproven in the real world — even if, like flow batteries, they rely on technologies that have existed at least in the lab for decades. And most data center operators do not want to be the first to deploy an unproven technology at scale. That has the majority of prospective customers hanging back, waiting to see how the current raft of pilot-scale projects pan out before they sign anything binding — which could prompt a rush on the relatively limited manufacturing capacity that exists for some of these technologies the minute one of them proves solid, according to Sisto.

“That's the natural tension,” Sisto said. “Everyone would love to wait and see, but at that point you have missed the boat.”

 

The University of Texas at Dallas recently announced the opening of its Batteries and Energy to Advance Commercialization and National Security – or BEACONS – facility, which aims to help commercialize new battery technologies, China-proof the lithium-ion battery supply chain and bolster the national battery workforce.

The facility is funded by a $30 million award from the U.S. Department of Defense, and is also collaborating with industry partners including Associated Universities Inc. and LEAP Manufacturing. 

“We want to have that supply chain resilience and independence from the Chinese supply chain,” said BEACONS Director Kyeongjae Cho. “So that even if things really go bad and China decides to cut off [access to] all of these critical mineral supplies, the [domestic battery supply] will not be impacted by that, especially those going to defense applications.”

DOD provides a lot of battery demand, Cho said, due to their need to operate energy-intensive technology in the field. The Pentagon’s battery supply chain is set to shrink after the 2024 National Defense Authorization Act barred DOD from procuring batteries from some Chinese-owned entities starting in October 2027.

The banned suppliers are China’s Contemporary Amperex Technology, BYD, Envision Energy, EVE Energy Company, Gotion High-tech and Hithium Energy Storage.

China currently dominates the “active materials production portion” of the lithium battery supply chain, according to a 2024 article from the Center for Strategic and International Studies.

“Previously, a lot of defense applications were purchasing batteries from Chinese manufacturers,” Cho said. “So that's creating this dependence on the Chinese supply, and under the unlikely but unfavorable scenario, our defense would be stuck in their supply chain. That's something we want to avoid.”

The program is particularly focused on advancing solid state battery technology, which is more commonly used for drones and defense applications than other alternative battery types like sodium-ion and zinc-ion, Cho said. 

The new facility includes a 3,500-square-foot “dry room,” which is a lab kept at below 1% relative humidity to protect moisture-sensitive materials and processes during battery manufacturing, the University of Texas at Dallas said in a release. It also features a solid electrolyte room, multiple flexible production lines to facilitate rapid development and testing of new battery technologies, and workspaces for training and industry collaboration, the school said.

In order to uncouple the U.S. supply chain from China, the facility has been working on developing critical mineral supply chain transparency, as “we need to diagnose the issues before trying to address them,” Cho said.

“That's been rapidly maturing in terms of identifying how different minerals are going through different steps, and then we are working on developing an independent, China-free critical mineral supply chain,” he added.

Doing so will likely involve relying on battery cathode companies in allied countries like Canada and Korea, Cho said, as it’s unlikely that the U.S. will be able to get up to speed on cathode development.

The facility aims to bolster the domestic workforce through training, and is partnering with community colleges in North Texas to make sure the state’s battery industry can tap workers with a range of expertise.

“To run any production line you need, typically, community college graduates, who are not moving around,” Cho said. “They usually find a job in their area, where their family and friends are. [So the companies] have to develop their own local workforce.”

There were 30 weather-related events in the United States and Canada that caused more than $1 billion in damages in 2024, but “none resulted in operator-initiated load shed, unlike previous events of a similar scale,” the North American Electric Reliability Corp. said in its annual State of Reliability report.

On whole, the bulk power system “remained reliable but challenged by adverse weather conditions and transitions in resource mix and usage,” according to the report. “Today’s transmission system is demonstrably more reliable and resilient with the severity and duration of outages declining,” the reliability watchdog said.

The North American grid is challenged by the proliferation of large loads, such as data centers, and the operating profile of inverter-based resources, NERC said. But “reliability improvements were observed in areas with high concentrations of battery energy storage systems,” also known as BESS.

The size and speed with which data centers are expanding across the country presents “a significant near-term reliability challenge,” NERC said.

Though there is uncertainty surrounding how much data center capacity will be built, and how quickly, experts agree they are driving up electricity demand. Data centers could account for 44% of U.S. electricity load growth from 2023 to 2028, Bain & Company said in an October analysis.

These large loads can be developed faster than the generation and transmission infrastructure needed to support them, “resulting in lower system stability,” NERC said in its report. “Additionally, the voltage sensitivity and rapidly changing, often unpredictable, power usage of these facilities creates new operating challenges.”

NERC said more accurate models of the operational characteristics of data centers “are essential to reliability to prevent instability caused by these large changes in electricity demand.”

There was also more than 45 GW of new inverter-based capacity added to the bulk power system in 2024, according to NERC’s report. “However, the response by IBRs to system disturbances continues to impact some solar facilities, with ride-through issues being observed at large battery storage and wind plants,” it said.

NERC issued an alert last month which provided recommendations for IBR operators around modeling and performance.

NERC’s report also highlights the potential for batteries to make the grid more reliable. Utility-scale battery storage in the United States is poised to more than double over the next two years and will close out 2026 at nearly 65 GW, the U.S. Energy Information Administration said in its Short Term Energy Outlook published Tuesday.

“Improvements in frequency response are being observed in areas of the country that have high concentrations of battery energy storage systems and incentives in place to encourage or require participation,” NERC said. 

In Texas, NERC said battery capacity increased to more than 10 GW in December, and an additional 19 GW is planned by the end of 2025.

“While all industrial battery installations can provide frequency support, in Texas RE, the provision of frequency support (when available) is mandated through a Reliability Standard,” NERC noted. “This requirement combined with the increasing amount of installed capacity, quick response times, and BESS often being in a state of partial charge has positioned these installations as a key part of the Texas Interconnection’s frequency response.”

The Texas grid operated through multiple instances last year where batteries provided up to 100% of the total capacity for frequency regulation services, the reliability organization said.

“These events provide supporting evidence that at current penetration levels, with proper requirements and incentives, BESS can improve primary frequency response, an essential reliability service,” said Jack Norris, NERC’s performance analysis manager.

“While challenges and concerns remain with the rapidly increasing penetration of these resources, their flexible capabilities are currently beneficial to reliability, bolstering their viability as a form of BPS energy storage,” he said.

Utility-scale battery storage in the United States is poised to more than double over the next two years and will close out 2026 at nearly 65 GW — a rapid rise from 17 GW in the first quarter of 2024.

The U.S. Energy Information Administration published its Short Term Energy Outlook, showing a rapid increase in anticipated energy storage resources. Counting projects larger than 1 MW in the electric power sector, EIA said domestic storage capacity will rise from about 28 GW at the end of Q1’25 to 64.9 GW at the end of 2026. 

Large-scale battery storage resources in the commercial and industrial sectors are expected to rise from about 100 MW to about 300 MW across the same time frame.

EIA’s data shows annual U.S. electricity generation rising from 4,180 billion kWh in 2023 to 4,490 billion kWh in 2026.

Monthly electricity demand is highest during the summer months in the United States, but despite a cooling degree forecast in line with last year’s weather EIA said it expects total U.S. electricity generation this summer will increase by 1%, or 14 billion kWh, compared with summer 2024. 

“We expect strong demand growth in the commercial sector because of the expansion of data centers,” EIA said.

EIA anticipates natural gas-fired power plants between June and September 2025 will generate 3% less than they did last summer “because of higher natural gas prices and the continuing increase in new solar generating capacity.”

Domestic solar generation this summer will grow by 33%, EIA said, and improving water supply in the western states will contribute to a 6% increase in U.S. hydroelectric generation.