Distributed Energy Resource Growth

North American utilities are “increasingly looking to distributed resources” to meet data centers’ rapidly growing power demand amid ongoing challenges for large-scale generation deployment, according to energy consultancy Wood Mackenzie.

Their interest spurred a surge in virtual power plant deployments last year, Wood Mackenzie Global Head of Grid Edge Ben Hertz-Shargel said in a Sept. 17 note. The numbers of active company deployments, unique offtakers for VPP capacity and monetized VPP programs all grew by at least one-third year over year, according to WoodMac’s data.

But overall VPP capacity in North America grew only 13.7%, to 37.5 GW, indicating “a market that is broadening faster than it is deepening” due to persistent barriers to adoption, Hertz-Shargel said.

Wood Mackenzie counted 1,940 North American virtual power plant deployments this year, up 33% from 2024. Its count of monetized VPP programs — which pay distributed energy resource owners to dispatch energy or curtail consumption — showed the number of programs rose 35% year over year, from 321 last year to 433 this year. 

The number of unique offtakers for VPP capacity increased 38% this year from 2024, WoodMac said. More than half of all offtakers increased the number of VPP deployments serving them by at least 30% year over year. And the top 25 offtakers each procured 100 MW or more in 2025. 

WoodMac attributed the increased offtake, in part, to an emerging “independent distributed power producer” business model. Independent distributed power producers, it explained, are electricity retailers that finance third-party-owned energy storage offerings through grid service revenue and energy arbitrage — charging batteries when electricity prices are low and discharging them when prices are high.

Third-party-owned energy storage retains relatively favorable regulatory treatment under the One Big Beautiful Bill Act, the Republican budget law that curtailed hundreds of billions of dollars in clean energy funding authorized by the Inflation Reduction Act of 2022.

WoodMac’s research suggests a correlation between growth in VPP offtakers and utility commitments to data center capacity. The consultancy found particularly robust VPP offtake in the PJM Interconnection and Electric Reliability Council of Texas regions, both of which have substantial existing and projected data center capacity. In July, American Electric Power said its utilities expect to interconnect 18 GW of data center capacity by 2030, largely in ERCOT and PJM.

In his note, Hertz-Shargel said the correlation could set up a win-win-win for utilities, data center operators and distributed energy resource owners.

“This drives home the opportunity for utilities and even hyperscalers themselves to procure new VPP capacity to offset data center coincident peak demand, enabling faster grid connection,” he said. “Homeowners and business owners [with onsite energy resources] might actually earn revenue from the connection of new data centers, offsetting potential bill increases.”

But the modest increase in capacity relative to deployments, offtakes and monetized programs reveals obstacles that must be overcome before VPPs can reach their full potential, Hertz-Shargel said.

Those obstacles include enrollment caps on utility VPP programs, power market reforms that reduce VPPs’ capacity accreditation and market barriers for small customers, he said.

Brattle Group principal and distributed energy resources expert Ryan Hledik said the findings align with what he’s seeing in the distributed energy market. But he’s optimistic that VPP capacity will scale soon, given the urgency utilities and data center operators feel to source electrons wherever they can find them.

“Data center load growth appeared almost overnight, and the industry’s appreciation that VPPs could play an important role in that area has emerged even more recently than that,” said Hledik, who was not involved in Wood Mackenzie’s research.

Hledik said VPP providers, utilities and data center companies “are still gearing up to align on the right solutions,” but that work hasn’t significantly impacted overall VPP capacity yet. 

“My hunch is that the growth over the next 12 to 18 months will be more noticeable, and over the next three to five years the growth could be explosive,” he said.

Hledik added that some individual VPP programs in states like California are rapidly adding capacity. He pointed to a Brattle Group report last month that showed California’s Demand Side Grid Support VPP discharged 539 MW of average output, or about half the output of a large nuclear reactor, on the evening of July 29. The report said DSGS could provide net system cost savings of between $28 million and $206 million through 2028.

The California legislature unexpectedly zeroed out funding for DSGS earlier this month. A spokesperson for California Gov. Gavin Newsom suggested the program is less important now amid a surge in new generation deployments.

“The reality is that California has rapidly deployed thousands of new megawatts in recent years meaning our grid is more resilient than it’s ever been,” the spokesperson told Utility Dive in an email.

California lawmakers approved a sweeping energy package at the end of the legislative session that does not include funding to continue two grid reliability programs, including a virtual power plant advocates believe is the largest in the world. 

Earlier this year, the state faced a $12 billion budget shortfall, and the two programs were in limbo for months as legislators negotiated down to the wire. The bills awaiting Gov. Gavin Newsom’s signature after the session closed Sept. 13 include proposals aimed at bringing down energy costs, expanding the Western grid and codifying virtual power plants in longterm planning.

Advocates say gutting the Demand Side Grid Support and Distributed Electricity Backup Assets programs threatens to undermine the state’s progress toward a more resilient grid that can respond to system stress by calling on batteries, electric vehicles, rooftop solar panels, smart thermostats and other energy resources that are increasingly common in homes, businesses and institutions.

Legislators created DSGS and DEBA in 2022 to try to improve reliability and avoid blackouts during emergencies. At one time, they were slated to receive nearly a billion dollars in state funds. 

Kate Unger, senior policy advisor for the California Solar and Storage Association, said the DSGS program alone has more than one gigawatt of enrolled capacity, of which about 750 MW is batteries. The program is run by the California Energy Commission and offers customers, utilities and/or aggregators compensation in exchange for allowing their resources to be dispatched at times of grid stress. 

A test event in July saw more than 500 MW of battery energy dispatched to the grid for two hours.

“I think we’re at a point now where I can actually see the program come to a grinding halt,” said Unger. “There appears to be a risk that DSGS providers and customers could participate in 2026 and not get paid.”

A study by The Brattle Group, commissioned by Sunrun and Tesla Energy, both of which participate in the DSGS program, concluded that the taxpayer-funded virtual power plant could reduce the need for gas peaker plants and has the potential to save ratepayers $206 million between 2025 and 2028. 

After several rounds of appropriations and clawbacks, the programs had been expected to receive more than $400 million through at least 2028, funded primarily from California’s Greenhouse Gas Reduction Fund, which is funded by its cap and trade program.

Their fate, however, rested on the reauthorization of the cap and trade program, which was the centerpiece of a sprawling energy package that Newsom pushed through. The legislature passed a bill reauthorizing cap and trade and rebranding it as “cap and invest,” but without the grid reliability funding. 

Edson Perez, senior principal at Advanced Energy United, expressed disappointment that the programs seemed to have been left on the cutting room floor amid intense negotiations and budget constraints. 

“It just went into the black box of negotiations,” he said. “It is a huge missed opportunity.”

Perez said overall, reauthorizing cap and trade was a “great achievement” and he expressed hope that legislators would find another way to fund the grid reliability programs early next year. 

“The Governor is steadfast in his commitment to building a more reliable, affordable, clean and safe power grid that can serve the evolving needs of millions of Californians in a hotter, drier climate,” a spokesperson for Newsom wrote in an email. “The reality is that California has rapidly deployed thousands of new megawatts in recent years meaning our grid is more resilient than it’s ever been.”

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By Uplight

In behavioral science, the 'attitude-behavior gap' describes nearly universal discrepancies between people's stated beliefs and their actual actions.

Perhaps nowhere is the evidence for this theory stronger than in energy. While 80% of customers say they want their energy provider to play an active role in helping them manage their energy usage, participation in demand-side management programs rarely exceeds 10% across the US; the national average for Demand Response is only 6.5%. A lack of awareness and education, insufficient incentives (whether real or perceived) and inconvenience are typically cited as major barriers.

Meanwhile, distributed energy resource (DER) adoption continues to grow, with projections of 217 GW–roughly 70% of bulk-system generation additions– through 2028. With capacity constraints and skyrocketing energy prices, the opportunity to integrate customer-owned DERs into programs that reduce peak demand and offer grid relief has never been greater.

This reveals a striking paradox: if customers want utility help adopting new energy technologies yet aren't using programs designed for this, why are they purchasing electric vehicles, heat pumps and smart thermostats by the millions? The answer is simple. While utilities see these as grid assets, customers purchase them for deeply personal reasons—owning cutting-edge technology, saving money or having a more comfortable home.

Without effective customer outreach, most customers don't know that rebates, incentives and demand programs exist. More than 80% of smart thermostats are sold without utility rebates or program enrollment. Utilities typically enroll less than 10% of these devices annually into DR programs, leaving significant untapped value.

In contrast, Uplight-run utility Marketplaces achieve over 50% 'pre-enrollment' in DR—bundling program enrollment and incentives at point of purchase—with some programs seeing up to 90% conversion. Our data consistently shows that simple, delightful customer experiences with clear expectations and sound value propositions enable mass-market participation. The trick is scaling this approach across all programs and channels.

The Customer Experience Imperative

Leading digital customer experience providers have mastered the art of personalization. Amazon's recommendation engine suggests products based on browsing and purchase history. Netflix curates content based on viewing patterns. These platforms leverage data to deliver the right message to the right customer at the right time, creating compelling user experiences that drive engagement and loyalty. When they suggest the 'next thing', they’re almost always right.

Utilities possess similar data assets—energy usage patterns, billing history, demographic information, AMI data and data from connected devices. They should be equally capable of delivering curated user experiences like:

Your cooling costs went up by 30% over the last several years, even after a weatherization program. Based on your home’s age, your AC unit may be ready for replacement. You might benefit from this heat pump incentive, paired with a smart thermostat and a TOU rate.

In practice, the diversity of internal data sources has made integrating systems and transforming raw data into actionable, personalized recommendations historically difficult to do at scale. Vendors like Uplight can cut through data silos to create comprehensive 360-degree customer views, enabling utilities to guide them along their individual energy journeys.

The Demand Stack Activation Multiplier

Once customers are activated through personalized engagement and have a positive program experience, they become prime candidates for additional utility offerings. This activation creates a multiplier effect throughout the Demand Stack, encompassing energy efficiency programs, dynamic rates and DR/VPPs.

The opportunity is substantial. Research from the National Renewable Energy Laboratory (NREL) found that electric vehicle owners show higher propensity to install solar panels, demonstrating that customers who adopt one DER technology are more likely to adopt additional ones. This creates natural pathways for expanding participation once initial engagement is established. Utilities can guide customers along their energy journey, building upon the initial offer to curate energy portfolios for each customer.

Homes and businesses are already investing in distributed energy resources. By effectively engaging customer-owned DERs, utilities can accelerate grid modernization, reduce infrastructure investment requirements and maximize returns on capital spending. Success requires creating compelling customer experiences that leverage personalized data and insights to build lasting relationships. Utilities that master this approach will bridge the gap between customer intentions and actions while positioning themselves as indispensable partners in their customers' energy futures.

Though the One Big Beautiful Bill Act sunsets the 25D residential solar tax credit at the end of this year, residential solar customers can still benefit from Inflation Reduction Act credits by using a third-party ownership structure that allows solar installers to claim the 48E investment tax credit and pass on those savings. 

In a blog post, Aurora Solar — a developer of software for solar sales and design — said “third-party ownership has never been more important,” and that TPO could be “the preferred option for some homeowners to access solar incentives after 2025.”

The 48E credit for solar requires projects that commence construction after July 4 next year be placed in service by the end of 2027. Projects that commence construction sooner can be placed in service anytime before Dec. 31, 2029, and still qualify for the credit. 

“TPO isn’t new — it already accounts for about 45% of residential installs in the U.S., with companies like Sunrun, Palmetto (LightReach), EnFin, and GoodLeap leading the charge,” Aurora Solar said.

Sunrun CEO Mary Powell said during an Aug. 6 earnings call that the company “is well positioned to continue to generate strong financial returns under the enacted legislation” as it “primarily benefits from the commercial investment tax credit known as 48E, as 94% of new customer additions are subscribers.”

Third-party solar financing generally comes in two forms: leasing agreements and power purchase agreements, according to a January explainer from the Environmental Protection Agency.

“In the lease model, a customer signs a contract with an installer/developer and pays for the use of a solar system over a specified period of time, rather than paying for the power generated,” EPA said. “In the PPA model, the solar energy system offsets the customer’s electric utility bill, and the developer sells the power generated to the customer at a fixed rate, typically lower than the local utility.”

Investment bank Jeffries said in an Aug. 7 note that it expects residential-focused solar company Sunrun to benefit in 2026 “as 25D expiration provides an assist for TPOs,” and noted that market consultants estimate TPOs will grow 25% in 2026 compared to this year.

Homeowners who don’t want to opt for a TPO structure can qualify for the 25D credit if their solar system's original installation is completed by the end of the year, even if it's not yet been placed in service. The new and burdensome foreign entity of concern restrictions don’t apply to the 25D credit, but they will apply to TPO systems hoping to qualify for the Section 48E credit.

“Further, an executive order from July 7th introduces additional uncertainty and could make it more difficult for TPO systems to continue qualifying for the [investment tax credit],” Wood Mackenzie Principal Analyst Zoë Gaston said in an August piece. “The future trajectory of the residential solar market is up in the air.”

Solar installation company SolShine Energy Alternatives noted in a blog post last month that “careful consideration must be given to options when working with third-party ownership providers in the future, particularly concerning the domestic content requirements.”

Other solar providers are similarly adapting in order to navigate the Trump administration’s rollback of the Inflation Reduction Act. Georgia BRIGHT Director Alicia Brown said Tuesday that the nonprofit is dealing with a complete funding cut to the federal Solar for All program by launching a new initiative called Safe Harbor as a Service, and working within the OBBBA’s guidelines to continue bringing low-cost solar to state residents.

“Treasury recently released guidance for ‘safe harboring’ the tax credits under current rules,” Brown said in a LinkedIn post. “If we can purchase equipment equal to at least 5% of a project's cost by the end of this year, we can lock in tax credit eligibility for that project through 2029 without triggering FEOC restrictions … This is a chance to create a glidepath into a post-ITC world.”

Growing up in Georgia, Montana Busch says he had two passions: technology and the environment. In 2007, when he was still a teenager, he founded Alternative Energy Southeast, a solar installer that today employs some 30 people between its offices in Athens and Savannah.

Business is booming, but Busch fears it will be short-lived. He saw a three to fourfold increase in requests for quotes “overnight” after President Donald Trump signed his signature tax and spending law that ended a 30% residential tax credit for homeowners to install solar nearly 10 years early. Third-party owners, such as those that offer lease agreements, can continue to get the credit until the end of 2026.

After the rush to claim the credit, Busch anticipates a sharp decline in residential customers. He hopes to replace the lost business with new commercial clients, but he’s concerned. He must also contend with rapidly-shifting tariffs and the potential abrupt end of Solar For All, a $7 billion federal program to expand access to solar power and which had just launched in Georgia to enthusiastic demand.

“We’ve sold a record number of projects in the past few weeks and, you know, it’s great in a lot of ways, but it’s also a big challenge for a business to ramp up and ramp down,” Busch said. “That’s what doesn’t make any sense about this: Solar provided means for someone like me ... to build a business from the ground up, i.e. the American Dream, right? But our own government is against our industry.”

A similar pattern of surging demand and unease appears to be happening nationwide, according to representatives for EnergySage, an online shopping tool where users can request and compare quotes for solar, storage and heat pumps. 

Overall, EnergySage saw a 59% month-over-month increase in registrations from potential customers from June to July. 

“We have seen some of our biggest weekly registration numbers in our entire history” since the company was founded in 2014, said Emily Walker, director of content and insights at EnergySage. “That’s very indicative of huge spikes in demand.”

But the company also conducted a survey of contractors and found that more than 90% said the tax credits going away would harm their business, with nearly two-thirds expecting "dramatic harm." One in four said they would consider leaving the industry altogether if the credits were cut.

“Pretty striking numbers in terms of the effect that this is going to have,” Walker said.

The nonprofit Interstate Renewable Energy Council conducts an annual solar jobs census that found the U.S. solar industry employed about 280,000 workers in 2023, the most recent year available. 

Walker pointed out that the industry is also enjoying some good news. Solar system installation prices remain at historic lows, though it’s early to gauge the impacts of tariffs. The company’s most recent marketplace report said solar prices dropped for the third six-month period in a row, hitting $2.50 per watt, the lowest median quoted price since the company began tracking data in 2014. Quoted storage prices also fell to a new record low of $999 per kilowatt-hour stored, it said. 

In the meantime, retail energy prices are rising and solar is growing more popular even in states without supportive policies, Walker said.

“I think a lot of it is energy independence, grid instability and rising electricity rates,” she said. “We’re expecting electricity prices to rise pretty significantly.”

Aurora Solar recently released the findings of a survey it did that found most respondents were not familiar with the details of what was in the tax and spending bill, but that expiration of the incentives made them more interested in pursuing installation.

“Under the current Trump administration, the renewable energy sector has lost something critical: long-term policy stability and investor confidence,” Chris Hopper, the CEO of Aurora Solar, said in a statement. “While I’m confident it will be rebuilt, the erosion of trust and capital in the meantime makes it harder for businesses to invest with conviction.”

Nearly every night over several weeks this summer, 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 this summer 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.”

There were 30 weather-related events in the United States and Canada that caused more than $1 billion in damages last year, 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.

Amid stiff headwinds for utility-scale renewables and gas, electricity system experts say utilities, industrial companies and other heavy power consumers may find some relief in a cheaper, faster and increasingly scalable solution: distributed generation and flexible loads, known as distributed energy resources, or DERs, that can be batched into virtual power plants or multi-megawatt demand response programs and deployed faster than utility-scale assets.

“There is an awareness that, oftentimes, distributed solar and distributed storage can come online much more quickly than larger resources … and a recognition of the role [they] can play in providing energy and in some cases capacity resources,” said Sean Gallagher, senior vice president of policy for the Solar Energy Industries Association.

Then again, nothing in the energy world is easy these days.

In April, President Donald Trump announced sweeping tariffs on imports from most U.S. trading partners. The targeted countries included major suppliers of solar panels, batteries and high-voltage electrical components, such as Vietnam (46%) and China (145% or more). Trump later announced a 90-day reduction to 10% for most countries other than China.

Distributed generation and storage assets may stand to benefit as developers look to sidestep bulk grid constraints, but they are not immune to supply chain challenges, particularly for larger projects, said Ravi Manghani, senior director of strategic sourcing at Anza Renewables, an energy data provider.

A perfect storm for utility-scale renewables?

Trump’s “Liberation Day” announcement was just the latest setback for the clean energy industry, which has been under siege since Jan. 20 despite providing 93% of new generating capacity in 2024. In a series of executive orders on his first day in office, Trump halted federal onshore and offshore wind permitting, withdrew all federal waters from offshore wind leasing, and declared an “energy emergency” that appeared to favor thermal and other high capacity-factor generating resources over wind, solar and batteries. A subsequent federal funding freeze, later partially rescinded, threw previously-authorized support for clean energy projects into limbo. Meanwhile, anti-renewables bills are proliferating in Texas, Oklahoma and other Republican-controlled states.

With the fate of Inflation Reduction Act tax credits up in the air as the U.S. Congress looks to offset an estimated $4.2 trillion in tax cuts this year, the clean energy sector could be in for more pain. Fully repealing the IRA’s technology-neutral Section 45Y investment and Section 48E production tax credits this year would reduce wind and solar deployments by about 50% over the next decade, The Brattle Group and ConservAmerica said in February.

That sort of pullback could jeopardize U.S. industrial growth, which is a driving factor in an expected 50% increase in electricity demand by 2035, ConservAmerica said. With new gas turbine costs rising fast and production capacity tied up until 2030, according to NextEra CEO John Ketchum, it may not be feasible to make up the shortfall with new fossil generation.

Because the U.S. already has tens of gigawatts of DERs that could be aggregated into VPPs within months, rather than years, some electricity system experts see smaller-scale resources as a potential stopgap should utility-scale renewables and storage development falter.

Enabling a more flexible grid

“DER” is a catch-all term for a broad range of generation resources, from residential solar arrays of a few kilowatts to grid-connected or behind-the-meter installations of 10 MW or more, and potentially flexible loads such as thermostats, water heaters and electric vehicles.

The U.S. has well over 100 GW of DERs that technically could be aggregated into VPPs and traditional demand response programs, but over 80% of that capacity is not, Wood Mackenzie said last year. Still, the firm identified 1,459 VPP deployments operating across 321 monetized market, utility and energy retailer programs.

Earlier this year, the Department of Energy pegged current U.S. VPP capacity at about 30 GW and said that figure could scale to 80 GW to 160 GW by 2030.

Utilities and state policymakers increasingly see the value in VPPs and DER aggregations, according to a February report from the NC Clean Energy Technology Center and the Smart Electric Power Alliance that catalogued more than 100 policy actions last year in 38 states and the District of Columbia. Many of those actions aim to harness the United States’ rapidly-growing distributed battery capacity or deploy sophisticated VPPs that use multiple categories of DERs, NCCETC Managing Director of Policy and Markets Autumn Proudlove said earlier this year.

In a flipbook released last year, RMI called out particularly innovative, multi-resource VPPs like those run by Puget Sound Energy in Washington (smart thermostats, behavioral load shaping, electric vehicles, water heaters and interruptible loads), Portland General Electric in Oregon (batteries, water heaters, behavioral load shaping and interruptible loads) and National Grid in New England (smart thermostats, batteries and technology-agnostic demand response).

Clean-energy groups are actively pushing supportive state policy and developing standardized templates for simpler, more efficient VPP programs, both key recommendations from last year’s Wood Mackenzie report.

“There’s a lot of enthusiasm around VPPs,” SEIA’s Gallagher said. “We are trying to templatize them so that they’re not as bespoke [and] are more straightforward to explain to utilities and customers.”

Though utility interest is “uneven” across the country, with some embracing DERs and others more resistant, eye-catching recent load growth forecasts help make the case, Gallagher said.

Speed and scale

In January, SEIA released a roadmap for 10 million distributed energy storage installations and 700 GWh of total deployed storage capacity by 2030. Utilities, too, are showing more ambition on DERs with plans for bigger, more sophisticated distributed resource aggregations.

In a February deal touted by Utah Gov. Spencer Cox, R, Rocky Mountain Power and distributed energy solutions provider Torus said they would collaborate on a commercial-and-industrial VPP that could provide up to 70 MW of flexible, behind-the-meter capacity by the middle of 2026.

“It’s no longer in question whether [this] is a path forward,” Torus CEO Nate Walkingshaw said in February. “[VPPs] can be seen at the same size, scale, quality and reliability as monolithic grid-tied architecture and are 100% viable today.”

In a regulatory filing in August, Xcel Energy’s Minnesota subsidiary proposed deploying and aggregating 440 MW of distributed solar and 400 MW of distributed storage to create what would likely be one of the United States’ largest VPPs.

“Xcel Energy believes distributed capacity can complement our existing plans for additional utility-scale renewable and firm dispatchable generation … [with] benefits including continued reliability, economic growth and providing our customers more options to adopt clean energy technologies,” Xcel spokesperson Josiah Mayo said in an email.

Meanwhile, utilities across the U.S. are working with developers to install larger-scale distributed energy resources with an eye to improving local and regional resilience.

In California, San Diego Gas & Electric partnered with EES and Mitsubishi Power Americas joint venture Prevalon to deploy multiple community microgrids totaling 180 MWh, and the company is now pursuing “half a dozen” similar opportunities right now, Prevalon President and CEO Tom Cornell said.

“We’ve seen a lot more utility inquiries in the past six to 12 months,” he said.

The value proposition for distributed batteries and firm generation is especially strong in regions where the grid is less reliable due to infrastructure challenges or weather-related risk, such as western North Carolina — hit hard by two hurricanes in 2024 — and other swaths of vertically-integrated utility territories across the Southeast, where developable land is abundant, Cornell said. 

In those territories, a typical 10-MW, 40- to 60-MWh system might take 12 months to site and permit, with equipment procurement happening in parallel and construction and commissioning taking a matter of months afterward, according to Cornell.

The Southeastern utilities “move especially fast … they understand that they can move quicker on these than any other resource,” he said.

Questions remain

Despite clear advantages over larger, less flexible, slower-to-deploy resources, DERs aren’t immune from the economic and policy uncertainty roiling the electricity sector, experts say.

California’s NEM 3.0 net metering tariff, effective for residential solar and storage systems that entered the state’s interconnection queue after April 14, 2023, dramatically reduced solar-only installations while boosting battery attachment rates. Until more independent system operators implement rules consistent with FERC Order 2222 and additional states enact policies that capture the full value of distributed generation and storage, the residential segment could see muted growth on a national level, Anza Renewables’ Manghani said.

State-level policy could also temper growth in the fast-growing community solar segment following a record-breaking 1.7-GW year in 2024, according to Wood Mackenzie data. Cumulative U.S. deployments reached 8.6 GW at the end of 2024, Wood Mackenzie said.

But a closer look at the numbers shows disproportionate contributions from a handful of pro-solar states — with Illinois, New York and Maine accounting for 83% of total capacity deployments last year — and policy uncertainty in emerging state markets as more mature markets saturate.

“Emerging markets have been slow to ramp up and program size caps limit the potential for growth in these states to make up for declines in larger markets,” Wood Mackenzie research analyst and lead report author Caitlin Connelly said in February. The upshot is an uncertainty band — as much as 40% to the downside and 37% to the upside — around Wood Mackenzie’s base case of 15 GW in cumulative deployments by 2029.

Cost is another concern for smaller-scale energy resources, Manghani said. For example, while the cost gap between distributed and utility-scale storage continues to close amid fierce supplier competition, “utility-scale projects still benefit from superior economies of scale, revenue generation market structures and financing advantages,” he said.

And Manghani emphasized that, like their bulk counterparts, distributed generation and storage systems and components are at least somewhat exposed to supply chain challenges.

“Ultimately, price trends will depend on policy shifts, manufacturing capacity expansion and how quickly suppliers adjust to demand,” he said.

To unlock the full potential of distributed energy resources in the next five to 10 years, utilities and grid operators must improve DER interconnection processes by increasing data access, streamlining study workflows and revising cost allocation approaches, according to a Jan. 16 report from the U.S. Department of Energy’s Interconnection Innovation e-Xchange, or i2X.

DER interconnection challenges are compounded by “significantly different resource availability, technology capabilities and grid impacts” for different technologies, such as wind, solar, small hydropower and energy storage, i2X said in its Distributed Energy Resource Interconnection Roadmap.

“Interconnection delays can definitely be a huge impediment for DERs, especially on the nonresidential side … [and] can also be a big reason why developers choose to exit certain states even with seemingly good economic opportunities,” said Hanna Nuttall, a U.S. distributed storage research analyst with Wood Mackenzie.

From 2010 and 2023, the number of U.S. residential rooftop solar PV systems rose from 89,000 to 4.7 million as the capacity of community solar installations grew from 1 GW to 7 GW, according to the i2X road map. Globally, energy storage capacity is expected to quadruple from 2018 to 2030, driven in large part by electric vehicles and related equipment, i2X said.

At the same time, interconnection waits are lengthening, even for relatively small DERs. In California, for example, the median interconnection wait for systems between 50 kW and 100 kW increased from about 60 days in 2010 to 100 days in 2022, i2X said.

“This is really a problem that can plague systems of any size,” Nuttall said. “Anecdotally, you could have a 100-kW solar system stuck in the queue for years.”

The i2X road map defines DERs as systems that meet three criteria: 

• Interconnected to distribution and sub-transmission systems not under Federal Energy Regulatory Commission jurisdiction;
• Sized from “small behind-the-meter, kW-scale systems to larger, in-front-of-the-meter systems less than 80 MW,” and,
• Technologies subject to interconnection study, such as wind, solar PV, small hydropower and energy storage, but generally not demand response or electric vehicles.

The i2X grouped its recommendations for improved DER interconnection processes into four broad groups: enhancing interconnection studies through “more transparent and accessible data sharing and strategic use of automation;” streamlining the interconnection process to reduce bottlenecks; promoting economic efficiency in interconnection to reduce costs to ratepayers; and addressing the performance of inverter-based DERs to maintain and enhance grid reliability and security.

“DOE put forth some really good recommendations here, some of which some utilities [already] do to a certain extent,” Nuttall said.

Those include publishing hosting capacity maps that improve DER developers’ and owners’ access to grid data; moving toward flexible interconnection practices that weigh the economic impact of unscheduled congestion-related curtailments against grid upgrade costs borne by developers; setting standard interconnection timelines; and reforming the “cost-causer pays” model to spread costs for interconnection-related upgrades among a wider group of beneficiaries, Nuttall said.

“We really need a lot of innovation to get DERs onto the system,” especially on more congested grids like ISO New England’s, she said.

The i2X road map set five targets to track progress on DER interconnection reform: shorter interconnection times; higher interconnection completion rates; better availability of interconnection data; no “[bulk power grid] disturbance events exacerbated by inaccurate DER modeling;” and faster service restorations after power outages.

By 2030, the road map aims for median interconnection times of one day or less and completion rates greater than 99% for systems smaller than 50 kW, under 75 days and greater than 90% for systems between 50 kW and 5 MW, and under 140 days and greater than 85% for systems 5 MW or larger. Additionally, it targets a 25% reduction in average outage duration and envisions “public, detailed and current queue data” available for all U.S. states and territories.