Firms that enlist homes to reduce energy demand — and costs — have long complained that utility data rules prevent them from helping in PJM. FERC agrees.

A recent ruling from federal regulators will let virtual power plants help meet surging energy demand in the county’s biggest energy market.

Late last month, the Federal Energy Regulatory Commission ordered PJM Interconnection to accept statistical sampling as a valid method for measuring the reliability of programs tapping into demand-response and virtual-power-plant programs, which pay customers to turn down energy use as needed. The decision requires the grid operator to reconsider strict data rules that had prevented providers of this carbon-free resource from participating in PJM’s constrained energy-capacity market.

In its decision, FERC ruled in favor of Voltus, which runs demand-response and virtual-power-plant programs, and the Mission:data Coalition, a nonprofit advocacy group, and against PJM’s desire to preserve its status quo.

FERC agreed with Voltus and Mission:data that, under its current rules, PJM is losing out on at least 4.9 gigawatts of capacity — the equivalent of several large power plants — ​“at a time when PJM is experiencing unprecedented load growth driven in part by hyperscale data center development, threatening reliability.”

Booming power demand from data centers and bottlenecks in power plant construction are not just threatening reliability in PJM but also driving up energy costs for the 67 million people it serves across 13 states. FERC found it would be ​“unjust and unreasonable” to allow the current rules to stand.

Last month’s ruling caps a yearslong fight from providers of demand-response and virtual-power-plant services.

“This is a huge win, and we’re really optimistic that it will unlock hundreds of megawatts of residential load over the next several years,” said Marissa Galizia, Voltus’ senior director of partnerships. FERC’s order makes clear that ​“PJM has the power to change the rules even while utilities aren’t providing the data,” she said.

At issue was PJM’s concern about relying on third-party demand-response aggregators to reduce household electricity demand when needed. PJM insisted that Voltus and other demand-response firms must furnish detailed evidence that participating households actually cut power when prompted to do so. Specifically, PJM required smart-meter data, which is collected in the service territories of most utilities PJM covers.

If firms could not produce that data, PJM would not count on — or pay for — that demand-response capacity to show up during times of peak demand.

But for the most part, demand-response firms could not get their hands on that data. That’s because, as Voltus and Mission:data argued to FERC, most of the major utilities in PJM territory have failed to make that data from their digital smart meters readily available.

It’s a catch-22. And as a result, PJM has missed out on gigawatts of demand-response capacity that could have helped alleviate the reliability and cost crunch it faces — and aggregator firms have been essentially locked out of the lucrative capacity market.

Utilities blame states’ data privacy regulations for their conservative management of smart-meter data. FERC doesn’t get to tell states how to manage those data privacy and data access rules, but it can compel PJM, which it has jurisdiction over, to accept alternative forms of data.

That’s what FERC did in the July decision.

Given the ​“significant barriers to obtaining interval meter data,” FERC told PJM to allow aggregators to use a statistical sampling method that the grid operator had relied on before smart meters existed. PJM also still allows this method for customers that don’t have smart meters. In light of those facts, FERC found that ​“statistical sampling is a valid method to approximate load reductions when interval meter data is not reasonably available.”

Both PJM staff and Monitoring Analytics, its independent market monitor, protested that letting demand-response companies use statistical methods could undermine reliability.

Monitoring Analytics argued that allowing statistical sampling would ​“degrade PJM’s ability to maintain resource adequacy and to correctly determine efficient capacity market prices through supply and demand.”

FERC disagreed, citing evidence presented by Mission:data and Voltus showing that statistical sampling can be as or more accurate than methods that use metered data when applied to large numbers of homes, as opposed to single large customers like factories.

The order won’t take effect immediately. FERC directed PJM to launch a proceeding to work with stakeholders to find a method that parties could agree on, with initial plans due within 45 days of FERC’s order.

“We’re going to be working with our partners to submit answers to the questions and propose what we’d like to see,” Voltus’ Galizia said. ​“Generally, we’d like to make it as easy as we can while guaranteeing that that process is as accurate as possible.”

FERC’s ruling comes at a tense time for PJM. Over the past year, the Trump administration and state governors have attacked the grid operator for failing to mitigate the huge increase in capacity market prices that are driving up utility rates and driving public anger against utilities and data center developers.

“I hope the decision sends a message to PJM and its stakeholders,” said Ken Schisler, chief legal and regulatory officer at CPower, a demand-response company that brought a similar complaint that FERC rejected in 2024 for lack of evidence. ​“The message is to stop the nonsense and to remove barriers that are keeping demand response from growing in the market.”

Michael Murray, president of Mission:data, hopes the ruling will also add fuel to his decade-long effort to make utilities and state regulators unblock smart-meter data that technically belongs to customers.

FERC’s order doesn’t address the underlying state-by-state data-access barriers that Mission:data is working on — the agency doesn’t have the jurisdiction to do so even if it wanted to.

Still, Murray hopes it will push state regulators to revisit their data-access policies, since ​“states may not like the remedies that FERC comes up with in this case or in other cases.”

And more broadly, he said, it’s the first time the agency has acknowledged just how critical this issue is.

“FERC has finally recognized that what I’ll call data blocking is not just an artifact of state privacy laws, and it’s not something to just ignore and say, ​‘Oh this is just a state matter,’” he said. ​“They definitely said that it rises to a Federal Power Act matter.”

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Tariffs and rising grid demand are spurring a revival, but high electricity costs and community concerns threaten to stall key new smelter projects.

America’s aluminum sector is growing again after years of decline, spurred by tariffs and a push to revive domestic manufacturing. But the voracious power needs of aluminum smelters and communities’ concerns about pollution still pose major hurdles to scaling up production.

Globally, a deficit in aluminum supply is expected to worsen this year following damage to major Middle Eastern smelters and disruptions in the Strait of Hormuz amid the ongoing U.S.-Iran conflict. At the same time, soaring U.S. power consumption is boosting demand for the versatile metal, as the makers of transformers, cables, and other electrical equipment race to build out the grid.

“There is very little cushion left anywhere in the system,” Jesse Gary, president and CEO of Century Aluminum, said on an earnings call last week. ​“In a market with no slack, the value of secure domestic units goes up.”

Chicago-based Century recently marked the return to full operations at its Mount Holly aluminum plant in South Carolina — one of only four remaining U.S. smelters. The facility has begun churning out another 50,000 metric tons of virgin, or primary, aluminum, raising total U.S. production by nearly 10%.

Mount Holly is, at the ripe age of 46, the country’s youngest smelter. In 2015, Century partially idled the plant because of high electricity costs — a persistent problem faced by virtually all smelters, which require hundreds of megawatts of continuous power to convert raw materials into metal. Last fall, Century reached a new long-term power agreement for its Mount Holly plant with the utility Santee Cooper. (Over half the utility’s power supply comes from coal-fired power plants, and about a quarter comes from natural gas and oil.)

Other smelter projects advancing in Oklahoma and Missouri are expected to further increase domestic supply, but their success largely hinges on their developers’ ability to access cheap, reliable electricity for the power-hungry operations.

In Oklahoma, Century and its joint-venture partner Emirates Global Aluminium are working to build a giant new smelter that would more than double the nation’s capacity for making primary aluminum. If all goes as planned, Oklahoma Primary Aluminum could break ground by the end of this year and start producing its ​“first hot metal by the end of 2029,” Gary said on the earnings call.

The proposed smelter is set to receive a $500 million grant from the Department of Energy, which Century landed in 2024 from of a Biden-era program to decarbonize U.S. industries. The project was sited in Inola, Oklahoma, partly because of the state’s abundant natural gas and wind energy resources and solar energy potential. Utility-scale wind and solar represent the fastest and most cost-effective resources for expanding grid capacity — and running a smelter on renewables would sharply reduce the planet-warming gases and toxic pollution associated with aluminum production.

Oklahoma Primary Aluminum has been pushing for more than a year to strike a competitive deal with the local utility, the Public Service Company of Oklahoma. Gary said the developers have ​“advanced negotiations toward a final energy contract,” which they’ll need to obtain before construction can begin. ​“Just know that we’re working hard and continue to make progress,” he said.

However, the proposed 750,000-metric-ton smelter is facing growing pushback from state political leaders and Oklahoma residents, who worry that the hulking facility will pollute the air and water and harm cattle and crops in northeastern Oklahoma, including on tribal lands.

In recent weeks, members of the Muscogee (Creek) Nation and Cherokee Nation have raised concerns about the project’s environmental impacts, with Muscogee leaders adopting a bill that opposes building and operating smelters on the reservation. Gentner Drummond, Oklahoma’s attorney general and a Republican gubernatorial candidate, has also opposed the smelter’s foreign ownership and pollution risks. On Aug. 11, he filed a motion to block construction of the smelter while his lawsuit against the project is pending.

Century and Emirates Global Aluminium claim the Inola facility will be significantly cleaner than existing U.S. smelters and will use the latest version of EGA’s smelter technology. ​“We’re working very closely with the community in Inola and elsewhere in Oklahoma to better understand what their concerns are and to make sure that they have all the facts about our technology and process,” Gary said.

Meanwhile, some 420 miles east of Inola, the company Magnitude 7 Metals is planning to partially reopen its idled aluminum smelter in New Madrid, Missouri, before the end of this year.

The manufacturer shut down operations in 2024 and laid off over 500 workers, after struggling with low aluminum prices and high power costs, Bloomberg reported. The 263,000-metric-ton facility represented about 30% of the nation’s aluminum production capacity at that time — and was Missouri’s single largest consumer of energy.

On July 1, Magnitude 7 Metals said it will restart about 75,000 metric tons of annual production at the facility. The company attributed the comeback to the Trump administration’s Section 232 aluminum tariffs, which raise the costs of importing aluminum for cars, cans, and construction. Last month, the White House also created a related tariff program that’s designed to further incentivize investment in new U.S. primary aluminum capacity.

Whether the tariffs can offset the inescapable challenge of electricity costs remains to be seen.

Annie Sartor, senior campaigns director at Industrious Labs, noted one potential roadblock for the Magnitude 7 Metals restart: Missouri’s ​“large load” electricity tariffs. The state adopted the policy in 2025 to ensure that major power users help cover the costs of improving grid infrastructure to support their increased demand. But while wealthy tech companies can afford those added expenses, they’ll only add insult to injury for aluminum producers.

“The smelter would face the same electricity cost structure as a data center — even though that same smelter has already curtailed operations twice [in 2016 and 2024] because of skyrocketing power costs,” Sartor said on LinkedIn. ​“The policy challenge is clear: a framework created to manage data center growth could unintentionally make it harder for manufacturers to operate, create jobs and support local economies.”

It’s also unclear how Magnitude 7 Metals plans to power its partially reopened smelter. The company did not immediately reply to Canary Media’s questions.

The facility was historically powered by the especially dirty New Madrid coal-fired power plant, which emitted the most nitrogen oxides from a power plant in the region and the country in 2020. Residents in southeastern Missouri who support restarting the smelter said they’re nevertheless concerned that it will drive up pollution, unless the smelter moves away from coal and toward clean energy, according to a March survey by Industrious Labs.

“Long-term economic investment will be more likely if this operation is powered by clean energy, especially solar and storage,” Jenn DeRose, Sierra Club’s Beyond Coal campaign strategist in Missouri, said in a July 1 statement. ​“Powering the smelter with clean energy will help ensure the smelter’s long-term viability by leveraging affordable, fixed-cost energy, and cleaner air for everyone who lives in New Madrid County and beyond.”

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ScottishPower’s Whitelee onshore wind farm could double its capacity with far fewer turbines. It’s an example of how much wind technology has improved.

It’s almost an ironclad law: Over time, wind turbines get taller, better, and more cost-effective.

A new proposed project in the U.K. demonstrates that. ScottishPower recently announced its intention to repower the U.K.’s largest onshore wind farm, a process that will involve replacing old turbines with state-of-the-art new ones. Once that is done, the wind farm will produce twice as much power with almost half the number of turbines.

The Whitelee wind facility, near Glasgow, was completed in 2008. The developers installed 140 turbines that stood 360 feet tall at the highest blade tip and could generate 2.3 megawatts each. By 2013, the site had been expanded with 3-MW turbines that stood 459 feet. Since then, Whitelee has produced up to 539 MW from its 215 turbines, storing some of that in a 50-MW battery on-site.

If the forthcoming upgrade gets regulatory signoff, the old turbines will be taken down and in their place will rise 124 new ones, measuring 787 feet tall and producing around 7 MW apiece. Collectively, they will be able to generate more than 1 gigawatt of carbon-free power when the wind blows fiercely.

“Repowering allows SPR [ScottishPower Renewables] to reuse existing site infrastructure and take advantage of new technologies resulting in increased electricity generation and ultimately, increased security of supply,” the company noted in a scoping document.

It’s a striking example of how far this clean energy technology has advanced in recent decades. Modern turbines have pushed to incrementally higher heights and broader wingspans, allowing them to generate far more electricity than their predecessors — and to do so at a cheaper unit price. This evolution supports onshore wind’s position as the cheapest of all the electricity sources on an unsubsidized basis, per the latest analysis by the financial advisory firm Lazard.

Repowerings like Whitelee’s could help the U.K. and the European Union shore up their energy security as the natural gas supply chain remains in war-torn upheaval. And while the U.S. government currently seeks to thwart this affordable energy source, there are signs that repowerings could add significant capacity in the coming years.

Benefits and trade-offs of wind repowering

The main appeal of repowering is to access the much greater clean power generation — but there are other benefits, too.

“It doesn’t take twice as long to service a turbine that’s twice as big, and you don’t have to do two foundations — you only need to do one,” said Kaj Skov Nielsen, a longtime wind power specialist who helped set up the control system at Whitelee.

Installing a new turbine also gives project owners an easy opportunity to add state-of-the-art sensors, Nielsen said. New sensors can detect birds and bats and slow the blades’ rotation to protect them. Others can spot potential mechanical issues, like debris that could cause problems in the gearbox, before they become catastrophic.

Older turbines have control systems that can stop the blades if they detect a fault. Newer systems can slow the rotation to a safe level based on the specific fault that is happening, Nielsen said, eking out more generation without endangering the equipment — ​“it’s a totally different game.”

That’s not to say repowering is easy. Larger equipment may exceed the weight limits on the roads and bridges to the project site, or height limits on underpasses along the route, Nielsen noted. Developers need to weigh the cost of upgrading that transportation infrastructure against the alternative of shipping in pieces and assembling them on-site, which adds more work on the back end. A developer also needs to strengthen foundations to support the weight of much larger turbines.

ScottishPower still needs consent from the Scottish ministers for the repowering, so it will go through a detailed assessment for impacts on the community and the environment. The repowering project has two big advantages in that process, compared with a brand-new project: It already secured permission to build many more turbines on the same land, and it would upgrade capacity without expanding into undeveloped countryside.

ScottishPower, for its part, has tried to make Whitelee welcoming to the broader community. The energy company acquired the site after it had been used for commercial logging and has invested in wide-scale restoration of the underlying peatland ecosystem. People can bike or hike around the premises, take guided bus tours, and enjoy the views from a visitor center that touts its ​“delicious cakes” from local vendors. The power company markets it with the hashtag #MoreThanAWindfarm.

Can the U.S. get on the wind repowering train?

Turbines of the size proposed for Whitelee have just started getting installed around the world, said BloombergNEF wind analyst Harrison Sholler. Chinese manufacturers have been pushing the boundaries of onshore turbine size, but those units are typically shut out of Europe and the U.S. because of geopolitical concerns. Instead, developers in those regions turn to manufacturers including Siemens Gamesa, Vestas, and Nordex, all of which now sell 7-MW onshore wind turbines; or GE, which has onshore models up to 6 MW.

A project in Brazil’s Bahia state installed a new 7-MW turbine last fall, touting it as the largest onshore turbine in the Americas.

“It’s established technology in the sense that they’re not that different from a 6-MW turbine, for example,” Sholler said. ​“They’re considered by the industry to be proven at scale.”

The U.S. might not have any turbines that big yet, but it does have plenty of installed turbines of the smaller vintage that ScottishPower seeks to replace. The U.S. average onshore wind turbine capacity has steadily ticked up from 0.8 MW in 2000 to 1.8 MW in 2010 to 3.5 MW in 2024, per the most recent accounting by Lawrence Berkeley National Laboratory. The country’s first 6-MW-turbine project came online that year in Oklahoma.

Of the 86 GW of new wind capacity BNEF expects the U.S. to build over the next decade, 10 GW will come from repowering, said Sholler. ​“Towards the early to mid-2030s, we expect repowering activity to ramp up as some of the larger wind farms are reaching the end of their operational life,” he noted.

BNEF expects the Northwest and Midwest will build the most repowered wind capacity in the next 10 years, with significant capacity popping up in Texas, California, and the mid-Atlantic. In California, repowerings will provide pretty much all new onshore wind capacity in that period, Sholler said, because all the good sites for onshore wind farms got developed decades ago, starting when the state initiated a subsidy in the 1980s.

That said, the largest U.S. repowering on BNEF’s radar for the next decade clocks in at just over 200 MW, a far cry from the projected 1 GW at the refurbished Whitelee.

“I don’t think we’re at the stage of market maturity where we’re starting to see those larger-scale projects start to repower in the U.S.” Sholler said. ​“But we will get there eventually.”

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