As low-income households face the dual burden of weather extremes and high energy costs, energy efficiency is an increasingly important strategy for both climate mitigation and lower utility bills.

Passive House standards — which create a building envelope so tight that central heating and cooling systems may not be needed at all — promise to dramatically slash energy costs, and are starting to appear in “stretch codes” for buildings, including in Massachusetts, Illinois, Washington and New York.

And while some builders are balking at the initial up-front cost, other developers are embracing passive house metrics as a solution for affordable multifamily housing.

“We’re trying to make zero energy, high performing buildings that are healthy and low energy mainstream everywhere,” said Katrin Klingenberg, co-founder and executive director of Passive House Institute-U.S., or Phius. 

Klingenberg says the additional work needed to meet an aggressive efficiency standard, is, in the long run, not that expensive. Constructing a building to passive standards is initially only about 3%-5% more expensive than building a conventional single family home, or 0%-3% more for multifamily construction, according to Phius.

“This is not rocket science… We’re just beefing up the envelope. We’re doing all the good building science, we’re doing all the healthy stuff. We’re downsizing the [heating and cooling] system, and now we need someone to optimize that process,” Klingenberg said. 

Phius in practice and action

A Phius-certified building does not employ a conventional central heating and cooling system. Instead, it depends on an air-tight building envelope, highly efficient ventilation and strategically positioned, high-performance windows to exploit solar gain during both winter and summer and maximize indoor comfort. 

The tight envelope for Phius buildings regulates indoor air temperature, which can be a literal lifesaver when power outages occur during extreme heat waves or cold snaps, said Doug Farr, founder and principal of architecture firm Farr Associates.

Farr pointed to the example of the Academy for Global Citizenship in Chicago, which was built to Phius standards. 

“There was a really cold snap in January. Somehow the power went out [and the building] was without electricity for two or three days. And the internal temperature in the building dropped two degrees over three days.”

Farr said that example shows a clear benefit to high efficiency that justifies the cost.

“You talk about the ultimate resilience where you’re not going to die in a power outage either in the summer or the winter. You know, that’s pretty valuable.” 

There is also a business case to be made for implementing Phius and other sustainability metrics into residential construction, such as lowered bills that can appeal to market-rate buyers and renters, and reduced long-term maintenance costs for building owners. 

AJ Patton, founder and CEO of 548 Enterprise in Chicago, says in response to questions about how to convince developers to consider factors beyond the bottom line, simply, “they shouldn’t.”

Instead, he touts lower operating costs for energy-efficiency metrics rather than climate mitigation when he pitches his projects to his colleagues. 

“I can’t sell people on climate change anymore,” he said. “If you don’t believe by now, the good Lord will catch you when He catch you.

“But if I can sell you on lowering your operating expenses, if I can sell you on the marketability, on the fact that your tenants will have 30%, 40% lower individual expenses, that’s a marketing angle from a developer owner, that’s what I push on my contemporaries,” Patton said. “And then that’s when they say, ‘if you’re telling the truth, and if your construction costs are not more significant than mine, then I’m sold.’”

Phius principles can require specialized materials and building practices, Klingenberg said. But practitioners are working toward finding ways to manage costs by sourcing domestically available materials rather than relying on imports.

“The more experienced an architect [or developer] gets, they understand that they can replace these specialized components with more generic materials and you can get the same effect,” Klingenberg said.

Patton is presently incorporating Phius principles as the lead developer for 3831 W Chicago Avenue, a mixed use development located on Chicago’s West Side. The project, billed as the largest passive house design project in the city to date, will cover an entire city block, incorporating approximately 60 mixed-income residential units and 9,000 sq ft of commercial and community space.

Another project, Sendero Verde, located in the East Harlem neighborhood of New York City, is the largest certified passive-house building in the United States with 709 units. Completed in April, Sendero Verde is designed to provide cool conditions in the summer and warmth during the winter — a vast improvement for the low-income and formerly unhoused individuals and families who live there.

Barriers and potential solutions

Even without large upfront building cost premiums and with the increased impact of economies of scale, improved technology and materials, many developers still feel constrained to cut costs, Farr said.

“There’s entire segments of the development spectrum in housing, even in multifamily housing in Chicago, where if you’re a developer of rental housing time and again …  they feel like they have no choice but to keep things as the construction as cheap as possible because their competitors all do. And then, some architecture firms only work with those ‘powerless’ developers and they get code-compliant buildings.”

But subsidies, such as federal low income housing credits, IRS tax breaks and resources from the Department of Energy also provide a means for developers to square the circle, especially for projects aimed toward very low-income residents. 

Nonetheless, making the numbers work often requires taking a long-term view of development, according to Brian Nowak, principal at Sweetgrass Design Studio in Minnesota. Nowak was the designer for Hillcrest Village, an affordable housing development in Northfield that does not utilize Phius building metrics, but does incorporate net-zero energy usage standards.

“It’s an investment over time, to build resilient, energy-efficient housing,” he told the Energy News Network in June 2023.

“That should be everyone’s goal. And if we don’t, for example, it affects our school system. It affects the employers at Northfield having people that are readily available to come in and fill the jobs that are needed.

“That’s a significant long-term benefit of a project like this. And that is not just your monthly rents on the building; it’s the cost of the utilities as well. When those utilities include your electricity and your heating and cooling that’s a really big deal.”

Developers like Patton are determined to incorporate sustainability metrics into affordable housing and commercial developments both because it’s good business and because it’s the right thing to do.

“I’m not going to solve every issue. I’m going to focus on clean air, clean water, and lowering people’s utility bills. That’s my focus. I’m not going to design the greatest architectural building. I’m not even interested in hiring those type of architects. 

“I had a lived experience of having my heat cut off in the middle of winter. I don’t want that to ever happen to anybody I know ever again,” Patton said. “So if I can lower somebody’s cost of living, that’s my sole focus. And there’s been a boatload of buy-in from that, because those are historically [not] things [present] in the communities I invest in.”

No longer a niche, Passive House standards becoming a solution for highly efficient affordable housing 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.

Snaking under city streets, behind residential drywall and into furnaces, ovens and other appliances, natural gas pipelines are a ubiquitous presence in U.S. buildings. The question of what to do with them as the planet warms has become a serious debate — dozens of U.S. cities and states have crafted plans to reduce reliance on natural gas, and more than 20 other states have passed laws to preempt that type of regulation.

Now, utilities around the nation have begun testing a controversial idea aimed at reducing the carbon footprint of gas lines, while keeping them in place. Nearly 20 utilities have laid out plans to inject lines with a blend of gas and hydrogen, the latter of which emits no carbon dioxide (CO2) — a major greenhouse gas — when combusted. Testing such blends, these companies say, is an essential step towards understanding the practice, which they argue will help reduce emissions and fight climate change.

Deploying more hydrogen is also a federal priority — the Inflation Reduction Act created a tax credit for hydrogen production, and the Bipartisan Infrastructure Law set aside $9.5 billion to support hydrogen development.

But a federal hydrogen strategy released last year suggests blending hydrogen into gas infrastructure should focus on industrial applications. Many environmental and customer advocates agree; they argue that the use of hydrogen blends in buildings — rather than to power industries that are hard to electrify — makes little sense.

“Every dollar you’re reinvesting into the gas system could be a dollar you’re using to electrify the system,” said Nat Skinner, program manager of the safety branch of the California Public Advocates Office, an independent state office that advocates for consumers in utility regulation. “Finding the right uses for hydrogen is appropriate. But I think being really careful and thoughtful about how we’re doing that is equally important.”

Nearly 30 projects focused on blending hydrogen into gas lines that serve homes and businesses have been proposed or are in operation in more than a dozen states, Floodlight found, and many more utilities have hinted at future proposals. If all are approved, the projects as proposed would cost at least $280 million — and many utilities are asking that customers pay for them.

As regulators consider the proposals, advocates are calling for them to weigh the prudence of the investment. In California — where electric rates have climbed steeply in recent years — the Sierra Club has argued that the projects are “an inappropriate use of ratepayer funds” and “wasteful experiments.”

Blending brings, risks, rewards

Hydrogen blending can be undertaken in a section of pipeline isolated from the rest of the gas network or in a larger “open” system that serves homes. Utilities can inject it in large transmission lines, which ferry gas from processing and storage locations to compressor stations, or into distribution lines, the smaller pipes that bring gas to buildings.

Because hydrogen releases only water vapor and heat when it’s burned, it’s considered a clean fuel. And unlike traditional wind and solar energy, it can produce enough heat to run industrial furnaces. Utilities have framed the fuel as a clear way to slash the emissions associated with their operations.

“These demonstration projects are an important step for us to adopt hydrogen blending statewide, which has the potential to be an effective way to replace fossil fuels,” said Neil Navin, the chief clean fuels officer at Southern California Gas (SoCalGas), in a March statement on its application for hydrogen blending pilots.

Burning hydrogen, particularly in homes, also presents certain risks. Hydrogen burns hotter than natural gas, which can increase emissions of nitrous oxide (NOx), a harmful air pollutant that can react with other elements in the air to produce damaging pollutants including small particulates and ozone.

Hydrogen is a smaller molecule than methane, the main ingredient in natural gas, and can leak more readily out of pipelines. Hydrogen is also flammable. And when certain metals absorb hydrogen atoms, they can become brittle over time, creating risks of pipeline cracks, depending on the materials the pipelines are made of.

There are also outstanding questions about how much hydrogen blending actually reduces greenhouse gas emissions.

Of the utilities that have offered details about the hydrogen source they plan to use for their pilot, roughly half plan to use “green hydrogen,” which is produced using clean electricity generated by renewable sources such as wind and solar. Today, fossil fuels power more than 90% of global hydrogen production, producing “gray hydrogen.”

Most utility blending pilots are targeting blends of up to 20% hydrogen. At those levels, research has shown that hydrogen would reduce carbon dioxide emissions by less than 10%, even when using hydrogen produced with clean manufacturing processes.

Some utilities have estimated the emissions impacts of their pilots. A CenterPoint Energy pilot in Minneapolis using blends of up to 5% green hydrogen was estimated to reduce carbon emissions by 1,200 metric tons per year, which is the approximate energy use of 156 homes. A project in New Jersey testing blends of 1% green hydrogen was estimated to reduce emissions enough to offset the energy use of roughly 24 homes.

Blending gray hydrogen may show no carbon benefit at all, according to some research. That’s in part because hydrogen produces one-third less energy by volume than natural gas, meaning three times the amount of hydrogen is needed to make up for the same unit of natural gas.

And hydrogen requires more energy to manufacture than it will later produce when it’s burned. For these reasons, some environmental groups say hydrogen is an inefficient way to decarbonize homes and businesses; some analysts have called the process “a crime against thermodynamics.”

“There are much better, readily available, more affordable ways to decarbonize buildings in the form of electrification and energy efficiency,” said Jim Dennison, a staff attorney at the Sierra Club.

Advocates including Dennison also worry that investing more in the natural gas system will delay electrification and allow utilities to keep their core pipeline businesses running. “I can see why that’s attractive to those utilities,” he said. “That doesn’t mean it makes sense for customers or the climate.”

‘We’re not sure’ of right mix

While the climate benefits are debated, some research and active projects indicate that burning blended fuel at certain levels can be safe. For decades, Hawaii Gas has used synthetic natural gas that contains 10-12% hydrogen. Countries including Chile, Australia, Portugal and Canada have also run hydrogen blending pilots.

And although pipelines can weather when carrying hydrogen, that’s less likely for distribution lines that reach homes because those pipes are often plastic, said Bri-Mathias Hodge, an associate professor in energy engineering at the University of Colorado-Boulder.

Hodge helped author a 2022 review of technical and regulatory limits on hydrogen and gas blending. With blends below 5%, Hodge said customers are unlikely to face risks or notice a difference in how their appliances or furnaces function.

More uncertainty exists around higher blends. “I think we’re not sure if below 20% or say, from 5 to 20% is safe,” said Ali Mosleh, an engineer at the University of California-Los Angeles who is spearheading hydrogen blend pilot testing with 44 partners, including utilities, to address knowledge gaps in the state.

Although Hodge at UC-Boulder thinks electrification is the more efficient choice for homes, he said the pilots can help utilities get comfortable with blending, which may eventually be applied elsewhere. “It’s not going to really move the needle in terms of decarbonization long term, but it’s a step in the right direction,” he said.

Steven Schueneman, the hydrogen development manager at utility Puget Sound Energy, which serves about 1.2 million electric and 900,000 gas customers in Washington, said incremental approaches like utility blending pilots will signal that hydrogen is a “real industry.” That could help the fuel gain a foothold in other areas, like industrial heat and aviation.

But Schueneman also acknowledges there remains uncertainty around whether hydrogen is the most cost-effective way to decarbonize buildings.

“It’s not clear that blending hydrogen is going to be a prudent decision at the end of the day,” he said.

Puget Sound Energy has conducted two small-scale blending pilots at a test facility. In the future, the utility plans to focus its hydrogen efforts on how blends may function in power plants, rather than in buildings. The nearly 30 blending pilots Floodlight tracked include only projects focused on use in buildings, but other utilities have proposed blending hydrogen at natural gas power plants, where the blend will be burned for electricity.

‘Cost is an essential consideration’

Blending pilots focused on buildings have been spearheaded by some of the largest utilities in the nation as well as smaller-scale gas providers, and are being considered from coast-to-coast.

Dominion Energy, which serves 4.5 million customers in 13 states, has laid out plans for three blending pilots, in Utah, South Carolina and Ohio. National Grid, which has 20 million customers, is pursuing a project in New York. And multiple large California utilities have proposed pilot programs.

Some utilities, such as Dominion and Minnesota-based Xcel Energy, did not reply to several requests for clarification on hydrogen blending plans, or replied to only some queries about their plans. But plans from certain utilities have been detailed in regulatory filings with state utility commissions.

The pilots for which cost data are available range in price from roughly $33,000 for Puget Sound Energy’s small-scale testing (which ratepayers did not fund) up to an estimated $63.5 million for a decade-long pilot proposed by California utility Pacific Gas & Electric (PG&E), which would focus on blending 5% at the start ranging up to 20% hydrogen in transmission gas lines.

If approved, customers would pay up to $94.2 million for PG&E’s pilot, because of the rate of return utilities are able to collect from customers. California utilities are aiming to recover more than $200 million in total from customers for their proposed pilots.

California regulators have rejected some previous blending proposals from utilities, saying companies should use “every reasonable attempt to use existing and other funds before requesting new funds.” Advocates including the Environmental Defense Fund (EDF) have argued that the projects are not in the public interest, particularly amid the state’s spiking utility bills.

“Cost is an essential consideration,” said Erin Murphy, a senior attorney at EDF. “When you’re passing on costs to ratepayers, you have to demonstrate that that is a prudent investment.”

Pilots have gotten pushback in other states, including Colorado and Oregon, where projects were recently dropped or delayed, and opposition has been fierce in California, which has the most pilots proposed to date. The mayor of Truckee, California, which could host a project, submitted a comment to regulators explaining the town does not support it. And following protests at two California universities that planned to collaborate on projects, utilities downsized the plans.

After student opposition at University of California-Irvine, SoCalGas reduced the scope of the project and proposed an additional pilot in Orange Cove, a small agricultural community of about 9,500 people. Ninety-six percent of Orange Cove’s population identifies as Hispanic or Latino, and roughly 47% of residents live below the federal poverty line, according to the U.S. Census.

Some Orange Cove residents also are concerned about blending, which SoCalGas hopes to test at up to 5% hydrogen levels. Genoveva Islas, who grew up there and is the executive director of Cultiva la Salud, a public health nonprofit based in nearby Fresno, said the local approval process lacked transparency and public input.

The project is slated to sit steps away from the Orange Cove football field, near the town’s high school, middle school and community center. “In short, I would just say it is concerning,” Islas said.

In an email, the utility told Floodlight that the city “proactively asked SoCalGas to undertake this project in its community” and said it was “expected to bring socioeconomic benefits to Orange Cove.” The utility also said it hosted a community engagement meeting about the project in Spanish and English and has provided fact sheets to the community in both languages.

In Colorado, where Xcel Energy had planned to blend hydrogen in an isolated neighborhood, some residents learned of the pilot from a journalist reporting on the project.

That has made some feel like unwilling test subjects in an experiment that others, like the Sierra Club’s Dennison, say are unnecessary. “The community’s immediate reaction is that they don’t want to be guinea pigs,” Islas said. “They do not understand how this decision was made without their involvement or their consent.”

The great majority of the projects, including the one in Orange Cove, are still under review by regulators. Meanwhile, researchers are undertaking more studies to understand the technical limits of blending.

“There are a lot of unknowns,” said Mosleh from UCLA. “Some fundamental research needs to be done.”

Utilities are trying hydrogen-blended fuels. There are a lot of unknowns. 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.

As president and CEO of Green Mountain Power in Vermont, Mary Powell developed the first utility partnership with Tesla to attach residential Powerwall batteries to the grid, providing backup clean power for the utility when needed. Customers could earn money by essentially filling the batteries at night and dispatching them during the day, Powell explained in a 2016 interview with Energy News Network. 

Today, such arrangements are increasingly promoted by clean energy advocates, who’ve dubbed distributed grid-connected batteries — plus solar — “virtual power plants” that allow homeowners and businesses to help out utilities during times of high demand. They’re also central to Powell’s current mission as head of the nation’s largest residential solar company.

Powell left Green Mountain in 2019 after two decades with the company, and in 2021 she became CEO of Sunrun. In an interview during a recent conference near Chicago, she spoke about how the culture of her former industry can slow the pace of innovation that’s much needed to address climate, cost and reliability concerns. 

“You’re talking about a 100-plus-year-old system and way of thinking, and you compound that with the fact that utilities’ whole culture is built for ‘slow and no’ and ‘protect, preserve, defend.’ For so many years, it’s been a one-way system,” Powell said. 

Virtual power plants are a prime example of the coming change. Powell said utilities’ experience with energy efficiency in recent decades provides a look at what might be coming for such pairings of solar and storage.

“I would say energy efficiency was the disruption — the first opportunity for utilities to start to think differently about their role and their mandate. And as we know, that took like 20 years, even for the most progressive utilities, to embrace.”

Utilities can generally choose to incorporate virtual power plants into their rate structures and grid services, and state regulators and legislatures can facilitate the concept through decisions, laws and policies that create incentives and provide standards. The Illinois legislature is considering a bill that would essentially allow the agency that procures power on behalf of utilities to contract with virtual power plants.  

Green Mountain Power was an early adopter of energy storage under Powell’s leadership, and broader adoption of the technology is ramping up quickly. The U.S. Department of Energy noted in a 2023 report that, “deploying 80-160 GW of virtual power plants (VPPs) — tripling current scale — by 2030 could support rapid electrification while redirecting grid spending from peaker plants to participants and reducing overall grid costs.” 

That means utilities will have to adapt quickly, and Powell sees a significant role for private developers in that transition. Powell describes Sunrun as a “clean energy lifestyle company,” branching into technologies like smart electric panels and EV charging. 

“When you think about customers having heat pumps, when you think about them having electric vehicles, you make sure that you’re leveraging all of that in a way that’s beneficial for the grid and beneficial for the customer.”

That focus on the end users of electricity is in part a bet that utilities’ need for solar power will eventually catch up to consumer demand.

“When I went to Sunrun I said to the team, ‘We’ve got to stop wandering around trying to convince every Tom, Dick and Harry utility to utilize our resources.’ We’re doing it, we just need to scale as fast as we can. 

“Because guess what, utilities are going to hit the wall, they are hitting the wall in some parts of the country, and they don’t have the ability to meet the kind of capacity demands that are projected over the next five years. They’re going to need our resources.”

Despite that expected market demand, Powell said legislative and regulatory bodies also have a role to “nudge utilities in the right direction.” Illinois in particular, she said, provides a strong example. 

“Illinois has done an amazing job. Making sure that rooftop solar is considered as part of the RPS [Renewable Portfolio Standard] is really thoughtful policy. And I am encouraged with a lot of the conversations about how we could leverage storage more. So yeah, we’re very bullish about Illinois.”

Powell also said she has no regrets about leaving the utility sector to work at Sunrun.  

“Frankly, even the fastest-moving utility was moving a little too slow for me. We weren’t scaling as fast as I would have loved us to be able to scale. It’s awesome to work on mission-driven work that you feel is valuable for the people you serve and for the planet at the same time.”

Sunrun CEO says utilities’ ‘slow and no’ culture gets in the way of energy innovation 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.

Environmental advocates say new rules announced Thursday by the U.S. Environmental Protection Agency should close a loophole that has helped power plant operators skirt responsibility for toxic coal ash pollution at scores of sites nationwide.

Two rules — part of a suite of new regulations on fossil fuel power plants that also include the first-ever carbon emissions limits — may offer the broadest tools yet for forcing cleanup of hundreds of ponds, landfills, and impoundments known to be holding coal ash, a byproduct of burning coal. 

Coal ash has been piling up for more than a century wherever coal has been burned as an energy source. Some has wound up in landfills. Some has been repurposed as construction fill. Some still sits in unlined ponds or piles next to power plants. It was mostly unregulated until recent years as its danger to public health became better known. 

The initial attempts to regulate coal ash were incomplete. The U.S. EPA’s 2015 coal ash rules covered only active repositories — exempting about half of all known dump sites including landfills, ponds closed before 2015, and sites where ash was scattered or dumped. Advocates have fought to expand the rules ever since.

The new, finalized Coal Combustion Residuals (CCR) rule essentially prohibits any pollution of groundwater or water bodies by coal plant sites, regardless of the exact source. 

Meanwhile the new Effluent Limitation Guidelines (ELGs) address wastewater released from power plants, including water used to clean bottom ash out of boilers. The effluent rules, proposed last spring, represent the first-ever regulations on coal plant wastewater, which includes contaminated water that has seeped through coal ash, and water drained from coal ash impoundments in preparation for closing. 

Companies have been able to avoid cleaning up even regulated coal ash ponds that were leaking, by blaming groundwater contamination on nearby unregulated coal ash sources, environmental attorneys have long argued. 

“So there’s a huge loophole that we will hopefully be closing,” said Environmental Integrity Project senior attorney Abel Russ during one of two online press conferences held by environmental attorneys and advocates before the rules’ release. “What EPA proposed would require basically sitewide corrective action and cleanup, whatever the source is, and owners will no longer be able to point to an unregulated unit and avoid a cleanup. This will also lead to clean up plans that are actually going to do what they’re supposed to do, which is restore groundwater quality.”

“We’ll finally eliminate the shell game of ‘Oh contamination came from that pile, not this pile,’” added Frank Holleman, coordinator of the Southern Environmental Law Center’s regional coal ash initiative. “The utilities will finally step up to the plate and be law-abiding citizens, and clean up this historic mess that the utilities are well capable of cleaning up and which should have been cleaned up years and years ago.”

The new rule will also for the first time regulate “historic” coal ash that has been scattered and dumped around coal plant sites and even in surrounding communities, often without records even being kept. 

“It may be underlying buildings, it may be underlying playgrounds, it’s basically everywhere,” said Sierra Club staff attorney Megan Wachspress. “The first step under the rule is for coal plant operators to actually figure out and delineate where this stuff is. When we talk about implementation, that’s making sure all of this dumped ash actually becomes accounted for.”  

‘Necessary and complementary’

Earthjustice senior attorney Lisa Evans praised the new rules, but noted that change depends on meaningful enforcement. Indeed, the 2015 federal rules were barely enforced until 2022, when the Biden administration’s EPA began issuing denials of cleanup extension requests and violation notices to coal ash site operators.  

Attorneys said the coal ash and ELG rules work in tandem, with the coal ash rules covering groundwater near coal ash impoundments, and the ELG rules addressing surface water near power plants — both coal and new gas plants.   

“The two rules are necessary and complementary to each other and point in the same direction, which is that they are contaminating groundwater, they’re contaminating the surface waters that run alongside them,” said Earthjustice attorney Thom Cmar. “Both standards work in complementary ways to set a high bar that points toward cleanup and environmental protection to make sure these dangerous sites are fully cleaned up.”

Holleman said that for decades, the powerful coal industry has avoided taking seemingly obvious precautionary measures.

“If you have solid waste with toxic substances in it, you can’t dump it in an unlined pit below the water table sitting next to a river, you’ve got to put it in a modern landfill,” said Holleman. “That’s true even with kitchen garbage in America. And secondly, if you discharge water containing toxic substances like arsenic, mercury, you’ve got to treat it before you discharge it in the river. That is the sum total, in many ways, of these two rules. That is not cutting edge. That’s just the basic, environmentally responsible — and I’d say humanely moral — thing to do.”

While advocates said they are pleased with the attention the Biden administration and specifically EPA Administrator Michael Regan have paid to coal ash, they worry gains could be precarious.

“If the next administration [has] no interest in enforcement, the public interest community will carry a very heavy burden,” said Evans, citing various measures taken by the Trump administration to weaken the federal coal ash rules and other coal-related protections. If Trump is elected in 2024, she said, “I have no doubt that the administration will either try the same thing again or not enforce the rule, which would be disastrous.”

While the coal ash rule would force the cleanup of coal plant sites even after the plants close, the wastewater rules could force companies to implement expensive pollution controls, or decide to close rather than making the investment.  

“It makes a lot of sense for coal plant operators to really take a hard look at the economics of retiring rather than expending additional funds, oftentimes captive ratepayer funds, retrofitting these units,” said Sierra Club senior attorney Joshua Smith.

Activist Dulce Ortiz said the new coal ash rules could help reverse the “painful history” of industrial pollution in her home of Waukegan in northern Illinois, the site of five of Illinois’s 11 Superfund sites. Ortiz and others have been demanding the cleanup of coal ash at a shuttered NRG coal plant on the Lake Michigan shore, with little response.

“Waukegan has dreamed for years and still does dream of revitalizing our lakefront. We have aspirational lakefront plans that have seen little to no success in coming to fruition in part because of the amount of contamination that remains at many of these sites… When we allow companies to pollute our communities and not force them to clean up, we deter future investment in these sites and our communities at large.”

Ortiz, founder of Clean Power Lake County and a Waukegan Township trustee, continued that, “My vision for my family and my community is that I can take my children swimming in Lake Michigan without worrying about toxic pollution, groundwater pollution…A lakefront with open space that respects our environment, where corporate profit does not override the health needs of our families… I want to see a clean energy future for Waukegan and all communities that have borne the brunt of coal ash pollution for decades.”

New EPA rules close a ‘huge loophole’ on coal ash, forcing wide-scale cleanup, advocates say 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.