Ensuring that traditionally disinvested Black and Brown communities are not left behind is essential for a just transition away from carbon-based energy sources. 

At the same time, many of these communities have vast stretches of vacant or underutilized properties, which could present opportunities for clean energy development. 

For instance, in Detroit, city officials are working with DTE Energy to build 33 MW of solar arrays on vacant property around the city. Detroit’s mayor has touted the project as a way to deal with blight while producing clean energy, but neighbors are divided.

Meanwhile, in the West Woodlawn neighborhood on Chicago’s South Side, a community-based geothermal project is intentionally bypassing vacant lots, focusing instead on placing the necessary loop fields in alleyways.

“Not every block in the neighborhood even has a vacant lot that could be leveraged,” said Andrew Barbeau, president of The Accelerate Group in Chicago, which is providing technical assistance for the geothermal pilot, in an email. “Further, communities often have other ambitions for that land, whether it is new housing development, parks, greenways, or other beneficial uses.” 

For Blacks in Green, the Chicago-based organization leading the geothermal project, recognition of the role of the project within a broader scope is central to an overall goal of generating economic development and a healthy environment within the community, said Nuri Madina, Sustainable Square Mile director, who serves as point person for the pilot.

“We know that the communities have been underserved. And underserved by definition means that we have not gotten our fair share of taxpayer investment in the communities. We know what our streets look like. And one of the major assets in the community, which is not really viewed as an asset, is our vacant lots,” Madina said.

The geothermal pilot 

Conventional geothermal systems require substantial plots of land to lay the subterranean loop fields that circulate both hot and cold water — land that is often scarce in densely populated urban areas. 

But while West Woodlawn has a number of vacant lots, they are not being utilized for the project. Instead, alleys provide a potential solution for constructing geothermal loop fields, along with allowing for connection points for houses and multifamily buildings within the pilot footprint, Barbeau said.

“The good news is that based on the system design, we have more than enough capacity in the alleys to serve the load of the blocks we have modeled. The modeling also so far is showing us that the shared network model would require 20-30%  less wells than if each home built their own system,” Barbeau said in an email.

Locating the bulk of the geothermal infrastructure in alleyways also sidesteps the underground congestion of existing gas, electric and water infrastructure on city streets, said Mark Nussbaum, owner and principal of Architectural Consulting Engineers in Oak Park, Illinois.

“There’s a lot of stuff happening out near the street. It doesn’t mean it’s not possible to coordinate it, but it’s just what’s nice about the alley concept is, it’s kind of unused for utilities typically,” Nussbaum said.

Blank slate versus bright future 

“White flight” and housing segregation have left many U.S. cities with sections of vacant or underinvested property, typically in communities populated by Black and Brown people. 

With roughly 60% of the land area of Chicago, Detroit nonetheless has a much larger proportion of vacant land — approximately 19 square miles. In some neighborhoods,  multiple blocks may only have a single structure remaining, if any at all.  

DTE Energy’s plan to build large-scale solar arrays on some of that land is supported by some residents and municipal officials as a means to reduce illegal dumping and other nuisance crimes while working toward meeting city climate goals — and reducing utility bills for residents. 

But there has also been pushback, largely focused on potential detrimental impact on property values in adjacent properties and limitations on future use of the sites themselves.

“Solar panels will disrupt and destroy entire neighborhoods. There will be no future affordable housing being built anywhere around a solar farm,” councilmember Angela Whitfield-Calloway said during a city council meeting in July, as reported by Planet Detroit. 

Whitfield-Calloway also questions why municipal buildings or sites outside the city limits had not been considered for the solar arrays.

In Chicago, a battery storage facility constructed as part of the Bronzeville Microgrid project administered by electric utility ComEd generated similar debate during an extended period of community input. ComEd officials said the location of the battery facility, in the middle of a stretch of vacant plots near the South Side Community Art Center, was strategic to the overall microgrid project. 

A 40-yard-long mural designed and created by local artists and mounted on the exposed long side of the battery storage facility not only serves to obscure the structure, but also to highlight prominent figures in Black history and culture. While reactions to the mural have been overwhelmingly positive, reception of the battery storage facility itself has been mixed. 

“There were thorough talks with the community and the art community in Bronzeville about what they wanted, what [ComEd] planned to do [with] that battery station, because they did not want it to be an eyesore … they did not want it to just be, you know, brick walls around infrastructure,” Jeremi Bryant, a resident of Bronzeville, told the Energy News Network in February 2021.

For Bruce Montgomery, founder of Bronzeville-based Entrepreneur Success Program and a member of the advisory council for the Community of the Future, the location of the battery storage facility precluded potentially more beneficial future development for the site.

“That lot in most communities probably would have ended up being invested in as more quality residential,” Montgomery told the Energy News Network in February 2021. “But now you’ve taken it up with this box car. … You’ve got big things sitting out in the middle of a vacant lot a couple of doors down from one of the most historic locations in Bronzeville.”

Creating ‘multiple benefits’

For Blacks in Green, what might appear to the casual observer as a vacant lot overtaken by weeds belies its ultimate potential — as an affordable, energy-efficient residential complex, small business owned by a community resident, a much needed basic amenity like a grocery stocking fresh produce — or a native plant garden to attract pollinators.

On June 17, 2023, Blacks in Green collaborated with the Delta Institute to hold a combined Juneteenth celebration and BioBlitz to identify potential sites for green infrastructure. Experts and community residents worked side-by-side to map and measure plant life, insect populations, drainage and other elements during a walking inventory of vacant lots in the area.

In the case of West Woodlawn, installation of geothermal loop fields in its alleys — versus locating them in vacant plots — presents an opportunity to promote climate resiliency through mitigation of persistent urban flooding, by utilizing permeable pavers to replace existing concrete or asphalt, said Madina.

“All of our programs are designed to create multiple benefits,” Madina said.

Projects like the West Woodlawn community geothermal project represent a drive to revive and reinvent Chicago’s Black Wall Street within what once constituted the redline-confined boundaries of the Black population drawn to the city during the Great Migration of the 20th Century.

“In most communities, the vacant lots are really indicative of a declining community. But what we have tried to do is take that negative and turn it into something positive. So if we can take those vacant lots with weeds and debris and turn them into beautiful gardens, that is a very significant improvement in the community,” Madina said.

“So [we] could improve the quality of life, improve the spirit of the people in the community… that vacant lot can provide more than just beauty. It can provide more than just comfort for the residents. It can also provide biodiversity, it can provide pollination, it can provide food for the residents.”

Correction: A 40-yard-long mural was mounted on the side of a ComEd battery storage facility to obscure the structure and highlight prominent figures in Black history and culture. An earlier version of this story misstated its size.

Vacant urban land poses complex questions for clean energy siting 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.

A three-judge panel in North Carolina upheld Duke Energy’s reduced payments to rooftop solar owners on Tuesday, unanimously rejecting claims from climate justice advocates that the smaller credits run afoul of state law.

The ruling upholds for now a scheme that took effect last October after Duke, some of the state’s oldest solar installers, and multiple clean energy groups reached a complicated truce to avoid the bruising battles over net metering seen in other states.

NC WARN, Environmental Working Group, and others opposed to the compromise argued that regulators adopted it without conducting their own analysis of the costs and benefits of net metering, a requirement of a 2017 statute. Such studies typically show that rooftop solar offers net benefits to the grid, contrary to utility claims.

The appellants rested their argument in part on a statement from one of the 2017 law’s authors, John Szoka, a Fayetteville Republican who served in the state House of Representatives for a decade. An Energy News Network article quoted in the appeal describes Szoka as “adamant” that the Utilities Commission, not Duke, should conduct the study.

The appeals court panel agreed, based on the plain text of the law. 

“The commission erred in concluding that it was not required to perform an investigation of the costs and benefits of customer-sited generation,” Judge Hunter Murphy, a Republican, wrote. 

But in a disappointing twist for the challengers, he continued, “however, the record reveals that the commission de facto performed such an investigation when it opened an investigation docket in response to [Duke’s] proposed revised net energy metering rates; permitted all interested parties to intervene; and accepted, compiled, and reviewed over 1,000 pages of evidence.”

Joined by two Democrats, Judges John Arrowood and Toby Hampson, Murphy’s opinion also rejected arguments that the commission erred by failing to consider all of the benefits of rooftop solar and by forcing solar owners to migrate to time-variable rates instead of allowing flat rates to stand.

“The commission properly considered the evidence before it and made appropriate findings of fact and conclusions of law,” Murphy wrote.

Many solar installers saw a dip in sales and interest in the last quarter of 2023 when the lower net metering credits took effect. But they were also hopeful about a new Duke program that rolled out this spring, which offers solar customers incentives to pair their arrays with home batteries.

Jim Warren, NC WARN executive director and an outspoken Duke critic, said in a press release that he and his allies would weigh an appeal to the state’s Supreme Court. 

“This ruling directly harms our once-growing solar power industry and the communities constantly battered by climate change driven by polluters like Duke Energy,” he said.

North Carolina appeals court upholds Duke Energy’s lower net metering rates 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.

California policymakers are searching for ways to rein in the cost of expanding the state’s power grid, which is necessary to combat climate change. Experts warn they’re missing an opportunity that’s right in front of them — taking advantage of the growing number of clean energy technologies owned by utility customers.

California ended its legislative session last month unable to pass a proposed legislative package to address rising electricity rates for customers of Pacific Gas & Electric, Southern California Edison, and San Diego Gas & Electric, which serve about three-quarters of the state’s residents.

Lawmakers also failed to pass several bills aimed at boosting the role battery-backed rooftop solar systems, electric vehicles, and electric heat pumps and water heaters can play in balancing the power that’s available on the grid.

Replacing fossil-fueled vehicles with EVs, and gas heating systems with heat pumps, will increase statewide electricity demand, requiring utilities to invest billions of dollars to upgrade their grids. But those same technologies can shift when they use power to avoid the handful of hours per year when demand spikes. That’s important, because the cost of building power grids is largely determined by the size of those spikes — and in turn is a core driver of California’s energy affordability crisis.

If the state can use distributed energy resources to shave a bit of demand from grid peaks, it stands to save big. One example: In an April report, consultancy Brattle Group projected that virtual power plants, which can shift when EVs and electric appliances draw from the grid or tap into customer solar and battery systems, could provide more than 15 percent of the state’s peak grid demand by 2035. That would amount to around $550 million per year in consumer savings. 

About $500 million of that would flow directly to the customers who own the devices, which could help defray the cost of buying EVs and heat pumps, two technologies that need to be rapidly adopted to meet climate goals. But because tapping into those devices would cost less than making large-scale investments, utilities — and by extension all of their customers — would save about $50 million per year by 2035, Brattle found.

“California’s affordability challenges are years in the making and are worsened by climate-driven impacts like heat waves and wildfires,” said Edson Perez, who leads trade group Advanced Energy United’s legislative and political engagement in California. ​“However, there are critical steps we can take now: optimizing our existing grid, maximizing the cost-effectiveness of essential grid upgrades, and fully leveraging available technologies like distributed energy resources.”

But as it stands, California isn’t putting the full weight of policy support behind these types of distributed energy programs.

Pilot programs have petered out, seen their budgets clawed back, or have been outright canceled. The scale of demand-side resources operating in the state has actually declined over the past decade, even as the state’s grid stresses have increased. And efforts to create statewide targets for distributed energy — like those that helped spur California’s rooftop-solar and home-battery leadership — have failed to gain traction, including a proposed bill in the state’s just-concluded legislative session.

Advocates say it’s time for the state to change that — especially since there’s an expiration date for capturing the value of DERs. Without policies to encourage utilities and customers to work together to realize the grid benefits of these technologies, utilities will simply build expensive, centralized infrastructure to meet rising electricity demand. Once that money is spent, potential savings can’t be realized, undermining the economic case for VPPs.

Unfortunately, utilities have clear incentives to discount the potential of VPPs as a money-saving tool, because they earn guaranteed rates of profit on capital investments like grid buildouts, but don’t for alternatives like VPPs. Plus, they’re held responsible for failing to keep pace with growing power demand — and are loath to rely on decentralized assets owned by customers in place of tried-and-true grid investments.

California’s VPP policy landscape

This utility reluctance may well explain why a roster of bills aimed at enlisting DERs to combat rising grid costs stalled in this year’s regular legislative session.

SB 1305 proposed requiring the California Public Utilities Commission to determine targets for utilities to ​“procure generation from cost-effective virtual power plants,” and then mandate that the utilities meet them.

Similar targets for rooftop solar and batteries have been valuable for boosting early-stage deployments in California, said Cliff Staton, head of government affairs and community relations at Renew Home, the company formed by the merger of Google Nest’s smart-thermostat energy-shifting service Nest Renew and California-based residential demand-response aggregator Ohmconnect.

“If you set the targets, you begin to provide the certainty to the industry that if you invest, there will be a return for your investment over time,” Staton said.

An early version of SB 1305 set hard percentage targets for VPP procurements by 2028 and by 2035. Those percentages were stripped from the bill later in the session, leaving the final targets up to CPUC discretion. The bill failed to clear a key legislative committee anyway.

Another bill that died in committee, AB 2891, would have expanded options for VPPs to capture the value of the peak load reductions they can provide. The legislation would have ordered the California Energy Commission to create methods for VPPs to reduce how much generation capacity each utility in the state must secure to meet peak grid demands in future years.

Only a handful of California’s community choice aggregators — the public entities that supply power to an increasing number of customers of the state’s major utilities — are using this approach today. But those CCAs have been able to start paying customers with solar and batteries for the value they can provide by reducing reliance on increasingly expensive contracts with centralized grid resources — mostly fossil-gas-fired power plants.

For more than a decade, state laws have called on the CPUC to create programs that reward customers for the energy and grid values provided by their solar panels, backup batteries, electric vehicles, and remote-controllable devices like smart thermostats and water heaters.

But these efforts have been plagued by an on-again, off-again approach from regulators and utilities. The California Energy Commission set a goal in 2023 of achieving 7 gigawatts of load flexibility from VPPs and other customer-owned resources by 2030; two of the CEC’s key contributions to that effort saw their budgets slashed this year.

Meanwhile, many of the programs launched by the CPUC over the past decade have stalled out due to overly complicated structures, or had their budgets reduced or canceled due to concerns over their cost-effectiveness.

The CPUC and the California Independent System Operator (CAISO), the entity responsible for managing California’s transmission grid and energy markets, argue that these programs have failed to perform as promised. Relying on them more would run the risk of eroding rather than improving grid reliability, they say.

But the companies engaging in these VPP programs — smart-thermostat providers like Renew Home and ecobee; solar and battery installers like sonnen, Sunrun, Sunnova, and Tesla; and demand-response providers like AutoGrid, CPower, Enel X, and Voltus — argue that overly complex and restrictive rules and compensation structures are to blame.

Adding to these challenges for would-be VPP providers is the declining value of rooftop solar. Major changes in California’s net-metering policies over the past two years have slashed the value of customer-owned solar systems, slowing the growth of the state’s leading rooftop solar market.

That’s a problem for VPP providers and advocates who see rooftop solar as an important way to help meet demand from households and businesses with EVs and heat pumps — and to charge up batteries with clean electricity that VPP programs can tap into later.

A host of bills were proposed to reset state policy to restore more value to customer-owned solar during this year’s legislative session. But only one — SB 1374, which restores compensation for schools that install solar — made it through.

California’s new rooftop solar regime does reward customers for adding batteries to store surplus solar power during the day and discharge it in evenings, when the grid faces its greatest and most costly stresses.

But solar and battery advocacy groups argue that those rewards haven’t counterbalanced the broader erosion of rooftop solar values — and that the VPP opportunities that have emerged in the state can’t yet be trusted to make up the remaining difference.

“It’s important for customers to find value in the investment they’ve made, and to help the grid and lower cost for all consumers,” said Meghan Nutting, executive vice president of government and regulatory affairs at Sunnova. ​“One of the problems with VPP programs so far is that it’s really tough to talk about that value proposition up front because programs are so short, you can’t count on them, or the funding isn’t there.”

Why grid costs and VPPs are intertwined 

At the same time, California policies that encourage people to buy other distributed energy resources — namely EVs and heat pumps — are under threat from rising electricity rates, which are eroding the benefits of switching from fossil fuels.

A controversial policy enacted this year to reduce the per-kilowatt-hour rates paid by customers of the state’s big three utilities in exchange for higher fixed costs may or may not ease that pressure. But both opponents and supporters of the policy agree that shifting the balance of fixed and variable electricity costs does little to address the underlying problems.

Programs that enlist those exact same distributed energy resources to ease grid stresses have a much clearer value proposition, on the other hand.

About half of the electricity bills of customers of California’s three big utilities is made up of fixed costs like grid investments. A majority of those investments are tied to building a grid robust enough to supply power not just for average needs, but during the few hours per year when electricity use peaks.

Those peaks are getting bigger as California’s climate goals encourage more EVs and heat pumps to come online, and the costs of dealing with that have only just begun to be built into utilities’ broader grid investment plans. A series of studies ordered by the CPUC found that adding demand from EVs and heat pumps to the grid could increase ratepayer costs by more than $50 billion by 2035 — or, depending on the approach taken, costs could be contained to less than half of that over the same timespan.

One key variable in those distinct cost forecasts is whether EVs can be programmed or incentivized to avoid charging all at once and overwhelming the grid. ​“Smart charging” programs that encourage EV owners to shift when they charge their cars could save California ratepayers tens of billions of dollars over the coming decade.

With the right policies and technologies in place, big new grid demands like EVs could actually become valuable resources for energy in their own right. SB 59, a bill that passed in this year’s legislative session after failing to make it last year, orders state agencies to study the proper role for regulation that could require automakers to enable their EVs to support ​“vehicle-to-grid” charging — sending power from EV batteries back to homes, buildings, or the grid at large.

The challenge for utilities and regulators is finding the right mix of approaches that can allow them to take advantage of EVs, heat pumps, residential solar and batteries, and other distributed resources such that they avoid either overbuilding or underbuilding the grid, said Merrian Borgeson, policy director for California climate and energy at the environmental nonprofit Natural Resources Defense Council.

“We have to be really careful with any new investment — but we do need to make new investments,” she said. ​“If we pull back too far on energizing loads like electric homes or EV trucks, we miss out on getting those loads connected.” 

California could cut utility bills with distributed energy. Why isn’t it? 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.

Correction: David Porter, vice president of electrification and sustainable energy strategy at EPRI, spoke generally about the challenges and opportunities of constructing data centers and coordinating with utilities. He did not speak specifically about the Southwest Virginia project.

Will Payne and Will Clear are all too aware of the skeptics.

But those doubters only fuel the duo’s vision for Southwest Virginia. The former Virginia state energy office bureaucrats turned private-sector consultants have an ambitious plan to repurpose land and backfill local taxes in communities left behind by the coal industry’s decline, and also pioneer new models for powering data centers with local clean energy.

Data Center Ridge is one piece of a nonprofit venture — Energy DELTA Lab — designed to transform 65,000 mostly contiguous acres of minelands where coal was king for decades into test sites that advance energy innovation. The project has the backing of Republican Gov. Glenn Youngkin, who announced an agreement last November establishing a framework for developing the land. 

“If I had a dollar for every time somebody asked why we’re wasting our time on this, I wouldn’t have to work,” Clear, a former chief deputy director with the state Department of Energy. “This isn’t a pipedream. What people need to understand is how long a project like this takes.” 

The first phase involves persuading tech companies to build solar-powered data centers on up to 2,000 acres of the now-defunct Bullitt Mine in Wise County. The facilities would be able to tap into underground mine water to help cool their servers. Eventually, they say, other energy sources such as wind turbines, pumped hydro storage, or small nuclear reactors could be added across the larger property.

“This is a big idea and we need someone who can share that vision,” said Payne, managing partner of Coalfield Strategies LLC. “We need developers who believe in ramped-up clean energy.” 

Glenn Davis, director of the Virginia Department of Energy, said a couple of key factors are driving the state’s interest in the lab. Many data center companies are exclusively seeking sites where they can access 100% clean energy, and new clean power generation could cushion the grid impact from the state’s booming data center sector.

“Southwest Virginia was the energy capital of the East Coast and I believe it will be again,” Davis said in an interview. “There’s a power void that needs to be filled and solar is part of that.” 

Dovetails with Youngkin energy plan

DELTA, shorthand for Discovery, Education, Learning & Technology Accelerator Lab, is just one enterprise Davis is tracking as he coordinates Youngkin’s all-of-the-above Energy Plan. 

Last fall, Youngkin said the intent is to attract private and public dollars to flesh out a portfolio that also draws wind, hydrogen, large-scale batteries, pumped-storage hydropower and eventually, perhaps, small modular nuclear reactors when and if that nascent technology matures. Any carbon-cutting realized by lab energy projects wouldn’t count toward Virginia’s landmark Clean Economy Act because the faraway area is served by a Lexington-based power company, Kentucky Utilities. The VCEA requires only the state’s largest investor-owned generators — Dominion Energy and Appalachian Power — to achieve a carbon-free grid by 2045 and 2050, respectively. 

That doesn’t bother Youngkin, Davis said.

“What’s driving the governor’s interest is jobs, businesses and an improved quality of life,” said Davis, appointed as an agency head in April 2023. “We’re excited because the opportunity for growth there is larger than any other in the state.” 

Dallas-based Energy Transfer owns the acreage, roughly 101 square miles. The lab is coordinating site development with Wise County officials and the landowner. Some of the acreage is still being mined for metallurgical coal, the type used for steelmaking and other industries. However, much of the property, including inactive Bullitt Mine, is being reclaimed. 

On paper, the dozen or so projects on the drawing board, including Data Center Ridge, could generate 1,600-plus jobs, add 1 GW of new power and induce $8.25 billion in private investments, Payne said. First, however, they have to move beyond the conversation stage. 

Payne and Clear, DELTA’s chief advisers, are counting on their matchmaking skills to revive a region often depicted as down on its heels. 

Clear grew up in Smyth County, east of Wise County. Payne recently moved to Washington County on the Virginia-Tennessee border. The Richmond native left a position as chief deputy at the state energy department in 2019 to direct InvestSWVA, an incubator invented to diversify the region’s economy and curb carbon emissions. Appalachian Grains was one of their previous energy-related joint ventures.

Tax revenues from data centers are the boost local governments need to fill the coal gap, they say. 

“Plain and simple, public safety, education, health care, municipal services and other core government sources are at risk of falling off a cliff if we do nothing,” said Clear. “We’re trying to solve this crisis.” 

Is SW Virginia the next ‘tertiary market’? 

Josh Levi, president of the Loudoun County-based Data Center Coalition, said Southwest Virginia shouldn’t be dismissed as too inaccessible or mountainous for data center development. 

Recently, the burgeoning industry began expanding into off-the-beaten path “tertiary markets,” he said. For instance, he pointed to a deal Amazon Web Service announced this year to spend $10 billion on two data center complexes in Mississippi. 

It was only a few years ago that the industry reached into secondary markets such as Columbus, Ohio, and San Antonio, Texas, after initially concentrating its investments primarily in Silicon Valley, New York-New Jersey, Dallas, Chicago, Northern Virginia, Atlanta and Phoenix. 

In Virginia alone, there’s a southward shift as more data centers pop up around Fredericksburg and Richmond. 

“What they’re doing is credible,” Levi said about Payne and Clear. “My understanding is that they have seen levels of interest from data center developers. Whether the opportunities they’re leveraging lines up with the business needs of data centers remains an open question.”   

For instance, he said, Southwest Virginia might be the right fit for backing up federal data but less so for applications such as live-streaming video or trading stocks. 

Loudoun County and surrounding Northern Virginia are home to almost 300 data centers, the biggest concentration of such campuses in the world. It’s the crossroads for roughly 70% of global internet traffic. 

Prolific construction of the mega-buildings that make cloud computing possible — combined with the accompanying need for transmission lines for electricity and water for cooling — have caused an uproar among community activists alarmed about their impact on local infrastructure and the environment.

Such large-scale growth prompted a tongue-in-cheek comment from Democratic state Sen. Danica Roem about exporting data centers from Prince William, the county she represents, to Tazewell County, just east of the proposed Data Center Ridge. 

In an interview with the Energy News Network, Roem said she would only support siting data centers in Southwest Virginia if the projects have widespread community buy-in, are powered with renewable energy and are built on reclaimed coal mines that don’t require clearcutting of forests, which serve as carbon dioxide sinks. Utility customers shouldn’t be saddled with paying for the expensive buildout of transmission infrastructure, she added. 

“I don’t want to simply shift the problems we’re having here to Southwest Virginia and create problems for the residents there,” Roem said. “If they’re building data centers there, are they going to stop digging in my district?”

Roem has joined other legislators introducing bills aimed at reining in data center growth and controlling the resources the buildings require. For instance, compared to a typical office building, the U.S. Energy Department estimates one data center needs 50 times more electricity. 

‘A lot of potential hurdles’ 

David Porter, vice president of electrification and sustainable energy strategy for the Palo Alto, Calif.-based Electric Power Research Institute, said there are numerous challenges and opportunities when it comes to coordinating data centers’ power needs with utilities.

“These data centers could be a really neat idea if they can work around a lot of potential hurdles,” Porter said. High on his checklist of potential limiting factors are access to a reliable electric grid connection, battery storage to fill gaps and “major league” fiber optic cable for communications.

He emphasized that even a modest number of data centers can’t rely on renewable energy 24/7. Backup power, typically provided by diesel-powered generators, is needed to keep the centers operating when the wind isn’t blowing and the sun isn’t shining.

As well, he said, even larger data centers in the gigawatt range generate far fewer jobs than a manufacturing center.

Payne and Clear said they are far from naïve about the difficulty of solving grid and broadband issues, which they know will take years, not months, to remedy, and that the jobs will be impactful in a region where the average annual income is $42,000.

“In Southwest Virginia, we’ve seen plenty of manufacturers pick up and leave, and that wouldn’t be the case with wind turbines and data centers.”

Their models show that one 36 MW data center, considered to be a mid-size project, would generate about 50 jobs paying $134,300 a year. In an ideal scenario, the size of Data Center Ridge would eventually expand more than 25-fold to 1,000 MW.

DELTA Lab recently collaborated with a local industrial facilities authority to offer a financial incentive for data center developers, Clear noted. It translates to Wise, Lee, Scott and Dickenson counties and the city of Norton offering a tax rate on data center equipment of 24 cents per $100 of assessed value. By far, it’s the lowest such rate in the state.

“The more persuasive argument for data centers here is about sustainability for local governments and their citizens,” Clear said. “This creates a new trajectory for tax collections for the next 50 years.”

Water source easy, electricity not so much 

The sites they’re eyeing for data centers are atop an estimated 6 billion to 10 billion gallons of underground 55-degree mine water, which offers a less-costly method for cooling the hot air generated by hundreds of servers. 

It’s not an aquifer. Over the years, rainwater has been filtered by the limestone and sandstone as it trickled through fissures and cracks and landed in cavities created as coal deposits were removed. The pools of water are as deep as 1,000 feet below the surface. 

Four years before ushering in DELTA Lab, Payne and Clear had procured a state grant to study the water supply. Since then, they have been collaborating with engineers to devise a closed-loop water system that could chill the centers and eventually pump the water back underground to be reused after the Earth removes the heat it absorbed. 

Drilling of test wells by a geotechnical company is scheduled to begin this fall. That exploration is funded by the federal government and managed by the U.S. Department of Energy. 

In the meantime, a looming challenge is securing the flow of electricity to and from Data Center Ridge. Even if on-site solar arrays with backup battery storage are the initial power source, the project needs to have sufficient substations, transmission lines and other infrastructure to tie into the grid. That way, excess electricity can be shipped out and “imported” electrons can fill any deficits. 

Payne and Clear are talking with Kentucky Utilities — which does business in Wise and four other Virginia counties as Old Dominion Power — about upgrading and adding infrastructure. That analysis is part of a larger effort spearheaded by county officials to meet long-term energy demand in Southwest Virginia. 

One plus, Clear said, is that siting the buildout of substations and transmission lines will be less difficult on property with one landowner. However, he also knows investor-owned utilities often aren’t keen on asking ratepayers to fund infrastructure built to serve one distant customer.

Davis said his agency would likely pursue federal Energy Department money to construct transmission infrastructure. 

Data Center Ridge has the potential to boost the utility’s renewable energy portfolio, which is 1% of a generation energy mix that is heavy on coal, 84%, and natural gas, 15%. 

Although every component of their blueprint presents a separate set of obstacles, the entrepreneurs say outsiders’ perception of Appalachia is the chief hindrance. 

“Even after making our case since 2019, dispelling myths about the region is our first challenge in getting developers down here,” Payne said. “They think everybody is on meth and lives in shanties.” 

They persist to prove their doubters wrong. 

“Everything is teed up here to be executed,” Clear said. “It’s getting that first domino to drop that’s really important.” 

Promoters of clean-energy data centers in Virginia coal country unfazed by doubters 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.

Solar customers and clean energy advocates are waiting to see if New Hampshire will continue its system for compensating customers who share excess power on the grid. 

State regulators at a recent hearing seemed unconvinced about the policy’s benefits, despite support from utilities, customers, and hundreds of residents who submitted public comments on a proposed extension. 

“This commission is highly skeptical of anything involving energy efficiency or clean energy, and focused almost solely on cost,” said Nick Krakoff, senior attorney for the Conservation Law Foundation in New Hampshire. 

These compensation plans, generally referred to as net metering, are widely considered one of the most effective policies for encouraging more solar adoption. Recently, however, several states have changed or considered changing their programs, as utilities object that the policies are too costly and some politicians and policymakers push for more purely market-based approaches. 

New Hampshire’s net metering rules haven’t been modified since they were established in 2017. The state’s public utilities commission opened a case to consider the question of whether and how to adjust the rules in September 2022. A year into the proceedings, the state’s major electric utilities — Eversource, Liberty Utilities, and Unitil — came out in support of continuing the existing system of net metering, despite the tendency of utilities nationwide to consistently push for lower net metering rates. The move was a welcome surprise for environmental advocates. 

“If you don’t have a compensation rate that’s high enough, you’re not going to have customers that are going to want to invest in solar panels or other renewable energy,” Krakoff said.

Striking an agreement

In early August, a diverse coalition including the utilities, the Conservation Law Foundation, Clean Energy New Hampshire, Granite State Hydropower Association, Standard Power of America, and Walmart reached a settlement agreement about the future of the policy. 

The agreement calls for the state to keep the current net metering structure in place for two years; at the end of two years, utilities would propose time-of-use rates for net metering, so the compensation rate more closely matches the real-time value of the power being sent into the grid. Also, any projects that join the net metering program during those two years will receive the same compensation for 20 years before transitioning into whatever new system is created by then (currently the compensation ends in 2040). 

An influx of public comments has also reflected wide support for the tenets of the agreement. Nearly 450 comments were submitted since the beginning of the year, more than Sam Evans-Brown, executive director of Clean Energy New Hampshire, has ever seen in a public utilities case, he said. The vast majority urge the commission to maintain the current net metering system. 

Peterborough resident Brian Stiefel was among those who filed comments. He and his wife installed 37 solar panels on their home in 2021, at a cost of $51,000. Though the solar doesn’t fully cover their electric bills, it provides $2,000 to $3,000 in savings per year, in large part due to net metering. 

“A big part of the decision to do this was the fact that the state would approve us for net metering,” Stiefel said in an interview. “If that’s going to change it could have a significant financial impact on everybody who has panels and is set up with net metering.”

An uncertain path forward

However, clean energy advocates say they have seen some signs in recent months that the commission might not be paying much attention to the benefits the system creates, while seeking out evidence that net metering creates a cost burden for consumers who aren’t part of the program. 

“The concern is that the chair is looking for a cost shift and is going to do whatever it takes to find one,” Evans-Brown said. 

Last spring, the commissioner requested a series of records in the case, several focused on gathering information about other states’ net metering programs — information that did not seem relevant to the decisions needed in New Hampshire, Evans-Brown said. The commission also requested, in a different docket, information about stranded cost recovery, which it then placed into the record on the net metering case as well, a move energy advocates interpreted as an attempt to focus on costs to the exclusion of benefits.

Then, in hearings on August 20 and 22, the commissioners asked questions that seemed focused on finding costs being passed on to consumers, even though there is simply no such evidence on the record, Krakoff said.

Advocates’ concerns are magnified by the commission’s history: In 2021, the commission drastically reduced funding for the state’s energy efficiency rebate and incentives. Though the utilities, consumer advocates, and environmental groups had come to an agreement to raise funding for the programs, the commission claimed that the program would burden consumers and that the state should focus on promoting market-based energy efficiency services. 

Current commission chair Daniel Goldner was one of the commissioners who signed the energy efficiency decision. During his confirmation hearing earlier that year, Goldner expressed skepticism about climate science, and advocates raised concerns about his lack of experience in the energy field.

“They expressed strong skepticism of energy efficiency and actually gutted the program,” Krakoff said, comparing that case to the present-day net metering proceedings. “It’s very concerning.”

Now advocates, homeowners, and other stakeholders can only wait to see what the commission decides and when they decide it. An order could come by the end of the year, said Evans-Brown, or the commissioners could decide to push the matter well into the new year — there are no deadlines set on the process. 

Should the commission in some way reject the settlement, there is still hope the legislature would take action to protect net metering. As part of the proceeding, state Sens. Kevin Avard, Howard Pearl, and David Watters submitted a letter explaining their belief that reducing net metering compensation would be against the goals of the legislature. 

“It is the intent of the legislature to preserve a viable net metering program in the state of New Hampshire, and we will take action to do so if necessary,” they wrote.

Resolving the question through legislative action, however, would leave the matter open and undecided for even longer, making it harder to encourage solar development in the state, advocates noted. 

“We were expecting this to be a challenging docket when this was first announced,” Evans-Brown said. “It’s frustrating, but not surprising.”

In net metering case, New Hampshire regulators focus on costs while ignoring benefits, 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.