Xcel Energy is proposing a new approach to powering the grid in Minnesota.

The utility recently told state regulators it wants to build a network of solar-powered energy storage hubs, located strategically on its grid and linked with technology so they can be operated in concert with each other.

The result would be what’s known as a “virtual power plant.” By simultaneously discharging the batteries, for example, the collection of distributed resources can function similar to a conventional power plant.

It’s a solution some clean energy advocates have long pushed for as an alternative to larger, centrally located projects that are more reliant on long-distance transmission and create fewer local economic benefits. Xcel’s new embrace of the concept likely reflects the evolving economics of clean energy and the urgency to replace generation from retiring coal-fired power plants.

“I welcome our now-agreement about the importance of distributed energy resources in their future procurement plans,” said John Farrell, director of the Energy Democracy Initiative at the Institute for Local Self-Reliance.

Virtual power plants 101

Virtual power plants use sophisticated software and technology to aggregate energy from batteries, smart thermostats, electric vehicles, storage and other connected devices. The clean energy nonprofit RMI predicts virtual power plants nationally could reduce peak loads by 60 gigawatts and cut annual energy expenditures by $17 billion by 2030.   

Several utilities, as well as solar and storage companies, have developed virtual power plant programs around the country. Perhaps the best-known is National Grid’s ConnectedSolutions program in New England, which includes residential batteries, electric vehicle batteries, and thermostats.  

In May, Colorado Gov. Jared Polis signed legislation requiring Xcel Energy to create a virtual power plant plan in that state by next February. 

Xcel is pitching the Minnesota project on its own as part of its latest long-range resource plan. In a recent Public Utilities Commission filing, Xcel proposes combining 440 megawatts of solar power with 400 megawatts of battery storage at dispersed locations. Designed to be flexible, the program might add backup generation and energy efficiency measures in the future. 

A virtual power plant, Xcel said, would save ratepayers money, improve reliability, accelerate clean energy development, and reduce energy disparities by playing assets in underserved communities. The “new approach equips us to confidently meet incoming load growth, deliver unique customer and community value, and support economic development,” the company said in its filing.

Kevin Coss, a spokesperson for the company, said the proposal “is part of a larger plan to better serve the grid and our customers while meeting anticipated growth in energy demand. The program would grow our distributed energy resources as a complement to our existing plans for additional utility-scale renewable and firm dispatchable generation to advance the clean energy transition.”

Advocates reaction

Clean energy advocates say the approach could reduce Xcel’s need to build more infrastructure at a time when electricity demand continues to grow and its fleet of aging fossil fuel plants reach closure dates.

A recent study in Illinois suggested that pairing solar with storage could be the most economical and environmentally beneficial way to maintain grid reliability as the state transitions to 100% clean energy.

“Utilities always treated distributed energy resources as something that happened to them and that they had to figure out how to accommodate because they were being told to,” said Will Kenworthy, Vote Solar’s Midwest regulatory director. 

The company’s interest in more distributed resources could lead to a more flexible grid, one that helps mitigate substations congestion and allows it to store energy from wind farms for use during high-demand periods, Kenworthy said.

One area of disagreement between the utility and some clean energy advocates is who should own the facilities. Unlike in Colorado, Xcel is proposing to own the Minnesota solar and storage hubs itself, collecting money to build them — plus a rate of return — from ratepayers. 

That’s not the best deal for customers, and it prevents local communities and developers from being able to share the financial benefits of distributed energy, said Farrell, of the Energy Democracy Initiative. If Xcel owns the virtual power plant, the cost could be higher than they would be with an open, competitive process.

Farrell pointed to the recent opposition to an Xcel electric vehicle charging plan in which it sought to own all of the chargers. Convenience stores and gas stations argued Xcel had an unfair market advantage as the incumbent utility and would own too much of the state’s charging network. Xcel withdrew the proposal in 2023 after regulators reduced the charging network’s size.

As Xcel’s plan evolves, Farrell wants Xcel to allow businesses, homeowners, and aggregators to also participate by selling their battery capacity or demand response into the program.

The Minnesota Solar Energy Industries Association, which promotes battery storage, also takes a dim view of Xcel owning a virtual power plant.

“This is an area where competition would likely provide better service, lower cost and more choice to ratepayers,” said regulatory and policy affairs director Curtis Zaun. “Monopolies are not particularly good at providing the best service at a reasonable rate because that is inconsistent with their investors’ interests.”

Getting the details right

Virtual power plants are different than demand response, such as thermostat savings programs, in that they add value to the grid “without any change needed to the homeowner’s behavior,” said Amy Heart, senior vice president for policy at Sunrun, a home solar and storage company that participates in virtual power plants in the Northeast and in Texas, California, and Puerto Rico. 

Heart said the “devil is in the details” when creating a robust demand response program. A program in Arizona failed, she said, because of the underperformance of the single company it selected to aggregate resources.

Sunrun developed a virtual power plant in four New England states, enrolling more than 5,000 solar and storage customers to share their capacity on the grid. In the summer of 2022, Sunrun’s virtual power plant shared more than 1.8 gigawatt hours of electricity.

Typically, Sunrun customers agree under contract to share a portion of their battery backup 30 to 60 times annually for three hours or less for each event. The process is automated, with Sunrun’s software connecting to customer batteries and sending utilities power during high-demand times or predictable peak loads. Customers receive payment for the electricity provided.  

Heart said the best systems are open to individual customers and aggregators using different battery storage brands. Giving a virtual power plant “room to grow, breathe, and adapt will be important,” she added.

The Xcel virtual power plant proposal is part of the multi-year Upper Midwest Integrated Resource Plan, which regulators have been reviewing and will likely approve, with many changes, later this year.

In Minnesota, Xcel Energy looks to mimic power plant with solar and storage networks is an article from Energy News Network, a nonprofit news service covering the clean energy transition. If you would like to support us please make a donation.

Southeastern Wisconsin and the Chicago area are emerging as major players in the national data center explosion, most notably with Microsoft’s $3.3 billion planned data complex near Racine, Wisconsin.

Clean energy advocates in the region say data centers pose both a risk and an opportunity, as they can put major stress on the grid, prolong the lives of coal plants and spark new natural gas plants, but also facilitate significant renewable energy investment. Wisconsin utility We Energies, for example, cited demand from data centers in its recent requests to the Public Service Commission for 1,300 MW of new gas generation. Microsoft, meanwhile, has promised to build renewables in the state while also likely creating demand for new or continued fossil fuel energy.

The organization Data Center Map shows more than a hundred data centers in the Chicago area and a handful in Southeastern Wisconsin, often located on the site of former coal plants or industrial operations. A data center is underway on the site of the shuttered State Line coal plant just across the border from Chicago in Indiana. The data center developer T5 recently announced plans for four to six data centers totaling 480 MW of capacity and costing as much as $6 billion in the Illinois town of Grayslake near the Wisconsin border, adding to data centers it already runs in the region.  

Virginia has long been known as “Data Center Alley,” with about 70% of global internet traffic passing through its servers, according to the Wall Street Journal. Dominion Energy said that because of data centers, its electricity demand in Virginia could quadruple and represent 40% of total demand in the state over the next 15 years. Georgia and Tennessee have also seen much data center construction and speculation. Utilities like TVA, Duke and Dominion have announced plans to build more gas plants and keep coal plants open longer in that region, along with building renewables.

Meanwhile, some experts say the Great Lakes region is an increasingly promising spot for data centers because of its cooler climate that reduces energy demand and the availability of water.

“There is no better place” for data centers than the Upper Midwest, said Josh Riedy, who helped design North Dakota’s first tier-three data center, referring to a data center with high reliability — on a scale of one to four tiers — that includes multiple power sources. Riedy also founded Thread, a grid maintenance software company that he’s marketing as especially helpful to serve data center demand.

“The Upper Midwest can export data around the globe,” Riedy said. We’re starting to see the tide turn, it’s just natural.”

Growing load

Projections abound regarding the way data centers — including those processing cryptocurrency and running AI applications — will increase energy demand nationally and end an era of stagnant load growth.

Last year, the Federal Energy Regulatory Commission predicted 4.7% load growth over the next five years, up from 2.6% previously estimated for five-year growth. Data centers “supercharged by the rise of artificial intelligence” will require between 9 and 13 more GW of electricity over the next five years, according to seven case studies analyzed in a December 2023 report by the Clean Grid Initiative, which does not include data center estimates for MISO or CAISO (California) regional transmission organizations. A McKinsey & Company report predicted 35 GW of total demand from data centers by 2030.  

Load growth sparked by data centers comes on top of a shift from fossil fuels to electric heating, cooling and transportation. A 2022 report commissioned by Clean Wisconsin and RENEW Wisconsin found load growth could increase to 166% of 2022 levels with building and vehicle electrification needed to meet the state’s goals of net-zero emissions by 2050.

“Everything from data centers to manufacturing to AI to cryptocurrency,” said Sam Dunaiski, executive director of RENEW Wisconsin. “These all could be triggers for new load, and it all could be coming to Wisconsin, though it’s not unique to Wisconsin. Things like solar and battery manufacturing are coming online that ironically need new load growth too. We think the best way to meet that new load both environmentally and economically is through renewables and transmission to go along with it. This is a great opportunity for a low-cost renewable energy boom in the state.”

Along with the generation demand, Riedy noted, come needs for grid updates and resiliency, which can ultimately help the grid as a whole.

“If you’ve built and designed a data center, you know the nature of them is in many ways fundamentally different than most energized structures,” Riedy said. “Walmart, for example, is going to consume power, but it will have peaks, and constant power is important but not in the way it is to a data center. With crypto mining or AI model training, you see machines running at near peak performance around the clock. That’s producing a type of strain on the grid that has few comparisons.”

Microsoft and more

Microsoft’s energy plans — like many details about the massive data project — are not yet clear, and the company’s ambitious climate goals give advocates hope that the company will finance much new renewable generation either on-site or through power purchase agreements. The company has announced it will build a 250 MW solar array in Wisconsin.

But Microsoft will likely also purchase power from We Energies, fueling advocates’ worries about new natural gas generation and rate increases for regular customers.

The data center will be located on the sprawling site between Milwaukee and Chicago that was previously slated for an enormous LCD screen factory by the company Foxconn. That plan was repeatedly scaled back and then scrapped in the face of economic issues and local opposition.

Citizens Utility Board executive director Tom Content noted that “under state law passed for Foxconn, Microsoft is eligible for discounted market-based electricity rates. They would pay basically for the transmission and distribution, but a portion of their rates would just be set at wholesale market rate,” rather than the retail amount customers usually pay.  

In February, a subsidiary of We Energies filed a plan with the Wisconsin Public Service Commission for an estimated $304 million in grid upgrades related to the Microsoft project. Public auditors filed a letter with the commission noting exemptions that allow less oversight because the project is in a special technology zone.

The Microsoft plan was touted by President Joe Biden as an example of reinvigorated Midwestern investment, but it has faced concerns about its energy and water use. Meanwhile Microsoft has faced setbacks globally in reaching its climate goals, in part because of the massive energy demand of artificial intelligence applications.

Cost concerns  

Advocates said utilities may use data centers to justify more investment that earns them a rate of return, even when it is not necessarily needed.

“We are concerned that there could be an overinflation of expected demand in order to capitalize on this trend and build more gas as a last-ditch effort,” said Ciaran Gallagher, energy and air manager for Clean Wisconsin.

“There’s a little bit of a sky-is-falling scenario here,” Dunaiski agreed. “In the early 2000s we saw this with load growth [projections] particularly around the internet. People thought the internet would cause our electricity generation needs to explode. They increased, but there were improvements that came with it — infrastructure getting more efficient, and software.”

That precedent raises questions about the rush to build out gas power to accommodate projected demand.

“Gas isn’t coal, but we shouldn’t be striving for the second worst option, for the environment or for our pocket books,” Dunaiski continued. “If we build these gas plants, customers will be paying for them for the next 20, 30 years.”

Gallagher noted that the EPA’s new rules for gas plants make new gas investments even more questionable.

“All the gas plants proposed in Wisconsin and across the country in relation to this demand from data centers will have to comply with these standards, and by 2032 either run not very often or reduce greenhouse gas emissions by 90% through carbon capture and sequestration or  low-carbon hydrogen,” Gallagher said. “That prompts the question: Is it worth the price tag to build these gas plants that could become stranded assets or have to spend additional money to comply with these rules?”

Using existing renewables or zero-emissions nuclear energy to power data centers can impact customers too. Content noted that this strategy “accomplishes the decarbonization goals for the tech companies and the reliability needs for the data center. But then you’re taking the fully depreciated, mostly paid-off asset on utilities’ books and having it serve one or two customers, and then the utilities will have to backfill that with a combination of natural gas, solar, storage, wind or future nuclear to serve the rest of the customers.”

“It’s on everybody’s mind how we’re going to tackle this in a way that ensures we don’t say no to economic development, but don’t make energy costs unaffordable,” said Content, noting that data centers have been a major topic of discussion among the National Association of State Utility Consumer Advocates – including at the organization’s conference in Madison in June.  

“Different states are trying different approaches,” Content said. “There’s talk of changing the way utility costs are divided up — currently among residential, industrial and commercial — and dividing it up four ways, with data centers becoming their own entity. Tech companies are pouring a lot of money into the development of these things. They have the wherewithal to contribute mightily to these projects.”

Renewable opportunities

Gallagher emphasized that renewable advocates are not opposed to data centers.

“We think data centers and the economic development that they can bring are not at odds with environmental protection and climate mitigation,” she said. “This can be a low-carbon industry but only if new additional renewables are built to supply all or most of their demands. We think that’s viable if renewables are cost-competitive with gas, and pairing renewables with storage can provide the type of reliability these data centers need.”

Riedy sees renewables and gas as a necessary mix to fuel data centers. While renewables’ intermittency might be seen as a barrier, he said renewables actually could have a unique role to play in energizing data centers – especially in the Midwest.

“In the heat of the day you’re delivering, so having alternate [energy] sources to peak-shave and normalize the cost of energizing that equipment is very important,” Riedy said. “It’s leading to a change in thinking around where to place data centers, that speaks to Wisconsin, the Dakotas. 

“The old way of doing things was generate power in one place, and transmit it for thousands of miles. What data centers are understanding with their insatiable and constant need for power is they are more logically placed by power generation so you can buy that off-peak power, to maintain that load consistently. Since solar and wind overproduce [at certain times], if you can harness that imbalance it’s somewhat of a win-win.”

Data centers offer energy peril and promise, with the Midwest increasingly in the crosshairs is an article from Energy News Network, a nonprofit news service covering the clean energy transition. If you would like to support us please make a donation.

More than 100 megawatts of planned solar projects throughout southeastern Massachusetts are facing lengthy delays as needed grid upgrades wait for state approval.

Arrays at Cape Cod schools, installations on an affordable housing complex on Martha’s Vineyard, and residential solar arrays for low-income homeowners are among the planned renewable energy developments that have been held up or reconfigured as regulators consider utility requests to upgrade substations and spread out the cost among customers. Until these improvements are approved and executed, no solar developments larger than 15 kilowatts for single-phase systems or 25 kilowatts for triple-phase systems can be connected to the grid in many of the covered areas. 

“This stalling runs counter to the state’s climate goals,” said Kate Warner, energy planner for the Martha’s Vineyard Commission, the regional planning agency for Dukes County. “The Vineyard wants to do our part, but we can’t because we can’t add any more significant solar to the grid.”

These delays are one more twist in the ongoing growing pains the state — and many places across the country — is experiencing as the move away from fossil fuels changes the flow of power through the system. As Massachusetts aims to go carbon-neutral by 2050, the transition to home heat pumps and electric vehicles is ramping up the need for electricity. At the same time, growing numbers of solar arrays are sending more and more power to the grid. The surge in both supply and demand has utilities and regulators scrambling to expand and strengthen the grid as quickly and cost-effectively as possible. 

Under previous rules in Massachusetts, a distributed generation project such as a new solar development would find itself on the hook for any expensive grid upgrades needed to connect the new power source to the system. Even though these improvements would benefit future projects, the development that triggered the need for the upgrades would have to bear the cost. 

To remedy this imbalance, the state energy department created a process that lets utilities propose plans to spread the cost burden of some grid upgrades among ratepayers, then recoup some of this money from future distributed generation projects and use it to reimburse ratepayers. These capital investment project proposals must be approved by utilities regulators. Massachusetts is the first state to create such a process. 

In April 2022, Eversource — which covers 140 towns around Boston and in the southeastern and western parts of the state — filed six such proposals relating to improvements in regions throughout southeastern Massachusetts. One of the proposals has been approved; the other five remain pending, raising questions about what happens next — and when. 

“The thinking was that it was going to be pretty quickly reviewed and approved — and that has not been the case,” said Mariel Marchand, power supply planner for the Cape Light Compact, the regional energy administrator that serves the 15 towns of Cape Cod and the six on Martha’s Vineyard.  

The Department of Public Utilities was unable to share any concrete timeline, noting that it intends to consider each application in detail. Because the process is new — in Massachusetts and beyond — there is no precedent for how long such deliberations should or usually do take. 

The capital investment project proposal for Cape Cod, which also impacts Martha’s Vineyard, calls for upgrading the distribution lines connected to five substations and additional equipment on three substations.

The goal is to make the infrastructure ready for a significant amount of solar and wind power to come online in coming years as part of the state’s push toward decarbonization and electrification, said Eversource spokesperson William Hinkle. 

On Martha’s Vineyard, the wait for these improvements means a 20-unit affordable housing development originally designed to maximize its solar production has had to go back to the drawing board. The project, intended to provide solar power and the associated savings to low-income residents, will now have to be configured as 10 smaller systems, each with its own interconnection. This arrangement, however, raises other regulatory questions about having more than one system on a single parcel of land, creating another delay. 

“That project probably could’ve been built by now, but it’s now held up in this more complicated planning process,” said Ben Underwood, co-founder and co-CEO of Resonant Energy, the solar developer on the project. 

On Cape Cod, the delays are slowing the deployment of a pilot program that provides low-income houses with solar panels, battery storage, and heat pumps. While many residential projects fall under the 15-kilowatt cap and can still be connected, the addition of batteries can increase the system size close to or over the limit, Marchand said.

“Before we recommend that this customer should have a battery, we have to make sure it can be installed,” she said. “It’s more work on our end, but we’re making it work.”

If the pending plans are rejected, the old system that would impose prohibitive costs on a small number of projects will remain in effect. If they are approved, it will still take significant time to complete the upgrades. At the moment, therefore, all anyone can do is wait. 

“Right now we are dead in the water,” Warner says.

As Massachusetts pioneers a new way to pay for grid upgrades, some solar projects are left waiting is an article from Energy News Network, a nonprofit news service covering the clean energy transition. If you would like to support us please make a donation.

Just about every week, Shawn Grant, who works for Salt Lake City-based Rocky Mountain Power, gets an inquiry from another utility looking for information about the company’s Wattsmart battery program.

“We want to do something. … How did you guys do it?’” Grant, the company’s customer innovation manager, says he’s often asked. “We’re always fielding those questions.” 

The program pays customers with solar who opt to install battery storage systems for the ability to use that stored electricity to help balance flows on the electric grid.

For customers, the benefits come in the form of lower electric bills and backup power in case of an outage. For Rocky Mountain Power, which has 1.2 million customers in Utah, Wyoming and Idaho, the program allows the company to harness the collective power stored in those distributed batteries to shave electric demand when it spikes rather than calling for more generation from a traditional power plant, among other uses.

“We’re using every battery every day to reduce demand on the grid,” Grant said. 

The concept is known as a virtual power plant, and grid operators, utilities, state regulators and lawmakers across the country are increasingly exploring the possibilities. They are seen as a cost-effective way to aid an electric grid that in many parts of the country is increasingly embattled by power plant retirements as well as difficulties building new, cleaner generation and the transmission lines they need — all at a time when huge projected electric demand increases loom.

“We’re now in this load-growth era,” said Robin Dutta, acting executive director at the Chesapeake Solar and Storage Association, a solar and storage industry group focused on Maryland, Virginia and Washington, D.C. “When you’re mitigating peak demand growth at the source, that’s perhaps the most cost effective way to modernize the grid.”

‘Faster, better, cheaper’   

Nearly 800,000 American homes installed a new solar or solar and energy storage system in 2023, according to the Solar Energy Industry Association. That growth set a record, with about 6.8 gigawatts installed, a 12% increase from 2022. Electric vehicles, another potential grid resource as a store of energy, also broke a sales record last year, despite consumer uptake being slower than some expected.

“These are devices that people are buying anyway because they’re faster, better, cheaper and virtual power plants allows everybody to leverage these devices while putting some money back in the pockets of people that bought the thing in the first place,”said Brian Turner, a director at Advanced Energy United, a clean energy trade group

The U.S. Department of Energy found in a report last year that large-scale deployment of virtual power plants “could help address demand increases and rising peaks at lower cost than conventional resources, reducing the energy costs for Americans — one in six of whom are already behind on electricity bills.”

They’re not a new concept, the DOE noted, adding that most existing virtual power plants are so-called demand response programs. In Virginia, for example, the commonwealth for years has run a program that enrolls hundreds of public facilities (airports, universities, K-12 schools, municipal buildings, water treatment plants and others) that agree to reduce or shift their electric demand to relieve strain on the grid. The DOE report says deploying 80 to 160 gigawatts of virtual power plants by 2030 could save about $10 billion in annual grid costs and would “direct grid spending back to electricity consumers.” At that scale, virtual power plants could meet between 10 and 20% of peak electric demand. The Rocky Mountain Institute, a research nonprofit focused on sustainability, called virtual power plants “a valuable and largely overlooked resource for advancing key grid objectives,” including reliability, affordability, decarbonization and electrification, among others.  

However, many states are starting to take notice of the potential:

• Maryland’s legislature just passed a bill that, among other provisions, requires utilities to create a pilot program to compensate owners of distributed energy resources like solar and battery storage for services they provide to the grid. “Ratepayers and consumers who invest in clean energy systems should see financial benefits when they provide meaningful grid services,” said Del. David Fraser-Hidalgo, a Democrat from Montgomery County who carried the House version of the bill. “Our DRIVE Act does just that; pairing battery storage with renewable generation will help Maryland achieve its clean energy goals, reduce our dependence on fossil fuels and mitigate the negative impacts of climate change.”
• Michigan, afflicted by expensive electric prices and high outage rates, has pending legislation, part of a package of pro-solar bills, that would create a virtual power plant program.
• In North Carolina, the state’s Utilities Commission has approved a Duke Energy pilot, called the PowerPair program, that it had directed the company to propose that will give customers incentives to install solar and storage. One group of customers will turn over control of the batteries to the utility and the other will participate in a test of “time-of-use rates,” which aim to shift customers’ usage to periods of lower demand, like running a dishwasher overnight, Utility Dive reported.
• In the summer of 2022, the New England Independent System Operator, which manages the electric grid for Maine, Vermont, New Hampshire, Massachusetts, Rhode Island and Connecticut, became the first such organization to use a virtual power plant, Politico’s E&E News reported. Sunrun, one of the nation’s largest solar installers, said it linked an estimated 5,000 small solar and battery systems to share 1.8 gigawatt hours of energy. In the summer of 2022, during a heat wave that sent temperatures soaring across New England states, residential and other non-utility solar installations reduced demand on the system by about 4,000 megawatts.
• The Pennsylvania Public Utility Commission announced in February that it was seeking comment on proposed rules related to use of distributed energy resources and virtual power plants. “Distributed resources provide the possibility for those who were traditionally consumers to play an active role in ensuring electric reliability and resiliency for themselves and their neighbors, and often in a less expensive way than traditional large generation that requires delivery infrastructure,” the commission’s chair and vice chair said in a joint statement. 
• Arizona Public Service, the largest electric utility in the state, counts 75,000 smart residential thermostats in its Cool Reward program, which provided nearly 110 megawatts of capacity during the summer of 2022. 
• A Colorado utility regulator is pushing for Xcel Energy to get a 50 megawatt virtual power plant up and running by the end of 2024, Utility Dive reported. The company, the state’s largest utility, already has a program called Renewable Battery Connect that allows it to discharge participating customers’ batteries during peak periods in exchange for financial incentives.
• In November, Puget Sound Energy, Washington’s largest utility, and AutoGrid, a California software company that provides distributed energy management systems, announced that they were expanding their partnership to develop a virtual power plant. “PSE’s VPP will reduce costs and help maintain reliable energy supply to its more than 1 million residential and business customers. Additionally, the VPP solution allows participating customers to receive monetary incentives for sharing assets with the grid and/or curtailing usage, something that’s financially beneficial for the community as well as helping the utility efficiently manage increasing electricity demand,” the companies said in a news release.

Why it matters

Experts who study and run the nation’s electric grid are worried about the pace of the energy transition. Old coal and gas plant retirements are accelerating, driven by economics, state clean energy policies and utilities’ own decarbonization goals. At the same time, massive backlogs in the queues to connect new power resources — overwhelmingly wind, solar and battery projects — in the regional transmission organizations that run the grid in much of the country mean big delays in replacing that retiring power generation. And after roughly a decade of flat electric demand, load growth is projected by many experts to explode as a result of transportation, industrial and home heating electrification, as well as a surge in data center development, among other factors. Throw in the fact that the construction of new transmission lines, essential to get excess power to where it might be urgently needed, has also stagnated and a problematic picture emerges. 

“Most utilities in the country are planning on pretty significant load growth,” said Turner from Advanced Energy United. ”They could plan to build a new peaker plant or they could plan to ‘build’ VPPs.”

That’s where utility incentives come into play.

Generally speaking, Turner said, utilities that operate transmission and distribution systems are more friendly to the idea. Companies that also own their own generation,  – and make a sizable chunk of their income from guaranteed profits on building new plants – , might not like the idea of a program that erodes the business case for a pricey new facility. 

“That’s why we have utility commissions,” Turner said. “They exist to say to the utility that virtual power plants are a cheaper option for the ratepayer and therefore you should implement it.”

However, even companies that might have resisted the idea are facing such dire electric-demand growth scenarios that virtual power plants may be attractive ways to get more flexibility out of the grid more quickly than building new generation.

“This is a way to get the capacity online faster and oftentimes cheaper,” Turner said. “Meeting that load growth is a real challenge in a lot of places.” 

‘Valuable and largely overlooked’: Interest in virtual power plants grows is an article from Energy News Network, a nonprofit news service covering the clean energy transition. If you would like to support us please make a donation.

The United States is facing a new energy crisis — one that could make the climate crisis even worse.

After more than 30 years of falling or flat demand for electricity, electric utilities are forecasting the nation will need the equivalent of about 34 new nuclear plants, or 38 gigawatts, over the next five years to supply power for data centers, electrification and new industry according to filings made to the Federal Energy Regulatory Commission and compiled by Grid Strategies.

Since those reports, several utilities have further increased their near-term forecasts. 

And those estimates don’t necessarily include the growth of hard-to-track, but energy-hogging cryptocurrency or cannabis farming, which are estimated to be using up to 2.3% and 1%, respectively, of the nation’s electricity. Energy demand in these industries has skyrocketed as the popularity of cryptocurrency and as legalization of marijuana have spread. 

The utilities “were either just caught unaware or not believing what they were hearing,” said Rob Gramlich, president of Grid Strategies, which provided a cumulative look of the demand in December.  

In response to this demand, which seems to have power providers in the United States flat-footed, many utilities want to build new power plants to burn methane, a fossil fuel also known as natural gas, or to delay closing their coal plants. 

“I can’t recall the last time I was so concerned about the U.S. energy trajectory, as major utilities maneuver for mass gas capacity expansion in the face of load growth. Unless course is changed … (greenhouse gas) goals are effectively dead,” Tyler Norris, a doctoral fellow at Duke University, said in a recent tweet.

The issue is also a global one, as a recent International Energy Agency report says electricity for data centers, including for AI and cryptocurrency, could double by 2026.  

At the same time, there hasn’t been enough construction of enough new transmission to bring renewables such as solar and wind to the grid. 

“We see (the gas buildout) as a huge threat — we are at a moment where we need to be phasing out fossil fuels and not locking it in for decades longer,” said Gudrun Thompson, energy program leader for the Southern Environmental Law Center. 

2022 projections ‘were so off’

Norris said in 2022 he pointed out in hearings on Duke Energy’s carbon plan that the company seemed to be “low-balling” the need for more electricity, including for the growing amount of electric vehicles. At about the same time, Georgia Power told regulators it only needed the equivalent of one more mid-sized power plant to meet growth for the rest of the decade after its two new nuclear units at Vogtle came online. 

But late last year, Georgia Power said it will need 17 times more electricity — the equivalent of four new nuclear units — than what it had forecast just 18 months earlier because of new data centers and manufacturing in this state. 

One Georgia Public Service Commissioner, known for backing Georgia Power, questioned whether the company should have seen that growth coming ahead of time.  

“Talk with me about why I should have any confidence whatsoever in these projections when the 2022 projections were so off,” a heated Tricia Pridemore asked in a PSC hearing.

Economic development interests in the state call the demand a measure of success. Georgia Gov. Brian Kemp has aggressively recruited new industry to the state, and its economic development arm and Georgia Power tout low electricity prices there as a way to attract that industry. 

The same is true in Texas, where data mining centers have requested the equivalent of roughly 41 new nuclear power plants to power their energy-intensive computer processes to find the cryptocurrency. 

Virginia cools on data centers

In Virginia, data centers are no longer as welcome as they once were. Dominion has threatened to turn away new centers, saying it can’t meet the power demand. 

The utility said in 2023 that demand for electricity from those centers would increase 376% by 2038. Even if that demand is tempered, Dominion still expects overall demand for power to grow by 85% over the next 15 years as consumers shift to electric appliances, heating and cooling units and vehicles.

The Tennessee Valley Authority is also a hotspot for new data centers, with 65% of its new load growth since 2019 coming from data centers. TVA has contracts from additional centers not yet online that will increase its load another 40% to 50%. The quasi-public utility has proposed or is building eight new natural gas plants to fill the demand. 

“The timeframe that they can get online has been aggressive on their part,” said Lori Stenger, TVA’s director of enterprise, forecasting and financial planning. 

This underscores one point made by observers: Data centers and data miners aren’t just going to places where power is cheap, but where they can get power the fastest. In fact, some crypto miners are purchasing coal plants to provide electricity for their operations.

Utilities say they can’t meet the skyrocketing growth with wind, solar and other renewable energy, but a large group of businesses including Google and Microsoft, beg to differ. The 400-member Clean Energy Buyers Association said fossil fuels are not aligned with their goals.

“Georgia Power’s proposals to add more fossil fuel resources into its resource mix in this docket send the wrong message to the business community and large customers evaluating Georgia as a place to do business,” said Priya Barua, CEBA’s director of market and policy innovation, in written testimony over Georgia Power’s request to add more capacity. 

Data on crypto energy use lacking

Despite the utility’s forecasts, it’s still unclear exactly how much power is needed. 

Jeremy Fisher, a principal advisor for climate and energy with the Sierra Club, said while data centers in Northern Virginia are using roughly the equivalent of three nuclear plants worth of energy, the centers themselves are building almost four times that much in backup diesel generation around their centers, according to a review of permitting data. The backup power could be an indication those centers are preparing for future growth, Fisher said.

“There’s such little data, it’s frustrating,” said Mandy DeRoche, a lawyer at Earthjustice who has been tracking data centers.

That lack of clarity around the nation’s electricity use — no single agency has a full picture of how much is needed or used  — was in the spotlight this year after  the federal Energy Information Administration sent an emergency request to cryptocurrency miners requiring them to share how much electricity they use. 

Texas miners sued to stop the request, and the EIA has agreed to go through a more formal process that will take longer to gather that data. 

At least one publicly traded Bitcoin miner, Riot, which sued the EIA to stop the data collection, highlighted the risk of such data becoming public in its annual report to the Securities and Exchange Commission last year.

“It is possible that mandatory surveys such as this will be used by the EIA to generate negative reports regarding the Bitcoin mining industry’s use of power and other resources, which could spur additional negative public sentiment and adverse legislative and regulatory action against us or the Bitcoin mining industry as a whole.”

Floodlight is a nonprofit newsroom that investigates the powerful interests stalling climate action.

Bitcoin, data centers fuel energy spike, risking climate goals  is an article from Energy News Network, a nonprofit news service covering the clean energy transition. If you would like to support us please make a donation.