Solar developers will pay a premium to build projects on prime farmland under new rules in the works in Maine. 

The state Department of Agriculture, Conservation and Forestry is drafting the rules based on a 2023 law that authorized it to collect extra fees from developers whose projects impact at least 5 acres of “high-value agricultural soils,” which regulators will define in rulemaking underway this summer. 

The program could involve a range of new fees for different kinds of farmland and project impacts, with money being set aside for “farmland conservation and solar mitigation projects.” Proponents hope the rules will push renewable energy development toward areas with less conservation value. 

“We would much rather see balanced solar siting than full-out moratoriums on solar energy development,” said Shelley Megquier, the policy and research director for Maine Farmland Trust, which supported the legislation authorizing the new rules. 

Critics, though, say the rules unfairly single out solar based only on anecdotal evidence of the industry’s impact on farmland. A recent report by the American Farmland Trust projected that low-density housing and other types of urban sprawl threaten to swallow more than 53,000 acres, or 5% of all Maine farmland, by 2040. 

The law also authorized the development of a similar scheme for wind and transmission projects that affect certain kinds of fish and wildlife habitat. 

Limited data, local concerns

Some advocates say the new fees single out renewables without clear evidence that a use like solar puts prime farmland more at risk than any other kind of development.

“The narrative around this has really been: how can we protect high-value farmland from solar development?” said Lindsay Bourgoine, the policy director for ReVision Energy, a major New England solar developer. “ReVision has a really big concern about the lack of data around that narrative.” 

Maine’s climate plan includes a goal of moving to 100% renewable electricity by 2040, and also aims to put 30% of the state’s land into conservation easements, including for farming, by 2030.

The state has already built close to a gigawatt of solar, most of it in smaller-scale projects. The five-acre minimum covered by the new compensation fees can support about a megawatt of solar.

Bourgoine’s company estimates that even if all of Maine’s existing solar projects under 5 megawatts had gone on prime agricultural lands, it would cover less than half a percent of all such land across the state. A recent report from the Center for Rural Affairs estimated a similar proportion for solar in Midwest states.

Groups that supported Maine’s new fee rules agreed that they hope legislators and state policymakers will turn their focus in the near future to both gathering more land-use data, and to considering expanding mitigation tools to uses that may be more common, such as housing, commercial development or roads. 

“If we’re talking about environmental impacts, we’re requiring mitigation of the one type of development that is benefiting the environment,” said conservation biologist and GIS manager Sarah Haggerty of Maine Audubon, which supported the bill to create the clean energy fee programs. 

Keeping farmers’ options open

Absent better data, Megquier said farmers and farm conservation groups like hers can only go on what they observe — which is “farmland being converted for solar production in pretty large amounts,” she said. 

“Some of that (is) what we would categorize as really high-value farmland, where unfortunately it’s being lost to agricultural production,” she said. “There may be farmers that would be interested in accessing that land to grow food for our communities.” 

Andy Smith and his partner run The Milkhouse dairy farm in Monmouth, Maine. They have their own small solar array and sit close to a power substation, and so have fielded extensive interest from solar developers who want to rent and build on some of their land. Some have offered more than $1,000 an acre for a 30-year lease, he said. 

Smith said he’s strongly supportive of an energy transition and sees frequent effects of increasing weather extremes on his farm. But he said solar is tough competition for farmers who lease or buy space from other landowners, often to grow hay to feed dairy cows like Smith’s. 

“If young people are trying to buy farmland, and they’re competing with solar developers, they’re not going to be able to buy farmland,” he said. 

For farmers that affirmatively want solar on their land, Megquier’s group hopes the new fee structure will incentivize projects to go on “marginal” land that’s less productive, unforested or disconnected from large active growing areas. 

“We hope that … this rulemaking takes those sorts of complexities into account,” she said. “We would want to see permitting for a solar development that supports current agricultural operation as sort of fast-tracked or, in some way, expedited.”

ReVision supports a similar outcome.

“We would just say that a landowner should have the default ability to be able to site solar on their property if the purpose of it is for revenue diversification to keep the farm in operation,” Bourgoine said.  

‘It gives us security’

Evelyn Norton is one such landowner. Her father raised dairy cows and harvested hay to feed them on her family’s farm in Livermore Falls, Maine. As that business declined and her dad got older, Norton said she realized, realistically, that she and her sister “were not going to be out on the tractors haying… and so we realized we needed to figure out what else we could do to bring income into the farm.” 

Numerous solar developers had contacted the family about putting an array on their land. Many were eyeing a particular flat, treeless area, close to grid infrastructure, with sandy soil. It had been the least productive plot for hay on the farm, Norton said.

“Someone referred to it as a Walt Disney solar farm property,” Norton said. “It was just like it was designed to be a solar array.” 

Her family worked with ReVision to build a community solar array on that 20 acres, covering about 15% of the farm’s total area. The grass beneath the panels is grazed by sheep, and the array provides power to five school districts — a nod to Evelyn’s mother, who was a long-time teacher.

Annual lease payments now provide the farm’s largest source of revenue, supplemented by various other agricultural uses, such as tree-growing and a farmer who rents space for his cattle. 

“We’re still wanting to stay as a one-unit farm and not have to sell off piece by piece. This allows us to do that,” Norton said. “It gives us the security to know that 135 acres is protected because of the 20 acres.”

Norton worries that the new fee structure, if not designed with the right exceptions, could prevent some farmers from using solar as she did to keep her farm viable. 

Pushing toward costlier approaches

Some advocates said they hope the rules will primarily help balance solar development costs so that farmland isn’t automatically the cheapest option. 

Smith, the dairy farmer in Monmouth, said he hopes at least the new fees will encourage development on “lower-quality soils.” But it’s easier said than done — these soils may be less well drained, for example, and contain areas classified as wetlands, leading to more regulatory complications. 

“It just often feels like, you know, a (good) solar site is going to be on well drained soil with southern exposure, which is also the best farmland there is,” he said. 

“We sincerely hope that this effort will not have a chilling effect… and, in some cases… could assist solar companies in terms of the predictability,” Megquier said. “The current structure is really not a structure. It’s very … project-to-project. And that is not to the benefit of advancing our conservation goals, nor is it to the benefit of advancing our renewable energy goals.” 

Under the new rules, regulators will have to define “dual-use agricultural and solar production,” such as agrivoltaics projects where crops and solar are co-located. Megquier hopes the new fees will incentivize this approach. 

For Smith, dual-use methods are the best hope for easing rural and neighbor backlash to solar energy, which he worries will slow its growth as a tool for fighting climate change. 

“It would really suck if the whole solar industry got like a black eye because of developing these open spaces,” he said. 

Haggerty, with Maine Audubon, said increasing costs for building on farmland could make more costly solar sites — including brownfields and developed spaces — more appealing for builders by comparison. 

“It may very well be that this legislation balances out some of those costs, you know — if you’re gonna have to mitigate… ag land or wildlife habitat, maybe it makes that brownfield more affordable, and it’s not as much cheaper to go elsewhere,” she said. “That’s one of the things that we hope to see.”

The state is currently gathering stakeholder input on a draft farmland rule expected out this summer. The Maine legislature will have to approve the eventual fee structures, which will apply to solar arrays that begin construction after Sept. 1, 2024.

As sprawl threatens farmland, proposed Maine rules single out just one competing land use: solar 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.

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Few places in California are as unforgiving for driving an electric car as the remote and sparsely populated Imperial Valley.

Only four fast-charging public stations are spread across the valley’s vast 4,500 square miles just north of the US-Mexico border, according to the U.S. Department of Energy. That means if you’re Greg Gelman — one of only about 1,200 Imperial County residents who own an electric car — traveling almost anywhere is a maddening logistical challenge.

“It’s been, I won’t say a nightmare, but it’s been very, very, very inconvenient,” Gelman said on a recent afternoon as he charged his all-electric Mercedes-Benz at a charging station in a Bank of America parking lot in El Centro. “Would I do it again? No.”

California’s electric charging “deserts” like the Imperial Valley pose one of the biggest obstacles to the state’s efforts to combat climate change and air pollution by electrifying cars and trucks.

Experts say the slow installation of chargers in California’s remote regions could jeopardize the state’s phaseout of new gas-powered cars. Under the state’s mandate, 35% of sales of 2026 models must be zero-emissions, ramping up to 68% in 2030 and 100% in 2035.

Nestled in the desert in California’s far southeast corner, Imperial County ranks dead last in electric car ownership among California counties with populations of 100,000 or more, according to a CalMatters analysis of 2023 data. Only 7 out of every 1,000 cars are battery-powered there, compared with 51 out of every 1,000 statewide.

High poverty and unemployment are a major factor in the region’s slow transition to electric cars, but its lack of public chargers are a big drawback, too.

People living in rural, low-income regions like the Imperial Valley have the least access to electric car chargers, according to a state Energy Commission analysis. More than two-thirds of California’s low-income residents are a 10-minute drive or longer from a publicly available fast charger.

Luis Olmedo, executive director of El Comite Civico del Valle, a nonprofit advocating for environmental justice, has battled for years against the Imperial Valley’s unhealthy air. Now he is making a bid to become its go-to supplier of charging stations for zero-emissions cars.

Olmedo isn’t waiting for businesses or the state to make chargers a reality in Imperial County. Instead, his group has embarked on a $5-million, high-stakes crusade to build a network of 40 fast chargers at various locations. It’s an open question whether his somewhat quixotic endeavor will succeed.

Electric car chargers “are an opportunity for us to be able to breathe cleaner air,” Olmedo said. “It’s about equity. It’s about justice. It’s about making sure that everybody has chargers.”

Esther Conrad, a researcher at Stanford University who focuses on environmental sustainability, said getting chargers in places like Imperial County is critical to California’s effort to transition to electric vehicles in an equitable way. Apartment dwellers and others who don’t have charging at home need nearby and reliable places to charge. 

“When you have a rural community that’s low-income and distant from other locations, it’s incredibly important to enable people to get places where they need to go,” Conrad said.

Hours from urban centers

A car is essential for traversing Imperial County, which is the most sparsely populated county in Southern California.

Its neighborhoods are vast distances from urban centers that provide the services that residents need: El Centro — its biggest town, home to about 44,000 people — is much closer to Mexicali, Mexico, than it is to San Diego, which is about a two-hour drive away, or Riverside, nearly three hours. Its highways and roads cross boundless fields of lettuce and other crops that give way to strip malls, apartments and suburban tracts — and then even more crops and open desert. 

If you drive an electric car the 109 miles from El Centro to Palm Springs, your route takes you through farmland, desert and around California’s largest lake, the Salton Sea, which is also one of its biggest environmental calamities.

The Salton Sea has been receding in recent years, causing toxic dust to blow into Imperial Valley towns. The region’s air quality is among the worst in the state, with dust storms and a brown haze emanating from agricultural burning and factories in the valley or from across the border in Mexicali, a city of a million people.

About 16% of Imperial County’s 179,000 residents have asthma, higher than the state average. The air violates national health standards for both fine particles, or soot, as well as ozone, the main ingredient of smog; both pollutants can trigger asthma attacks and other respiratory diseases.

More than 85% of Imperial County’s residents are Latino, and Spanish is widely spoken here. Agriculture is a major employer, and many businesses are dependent on cross-border trade and traffic from Mexico. The county’s median household income is $53,847, much lower than the statewide median, and 21% of people live in poverty.

Now the discovery of lithium, used to manufacture EV batteries, at the Salton Sea has the potential to transform the region’s economy. State officials say the deposit could produce 600,000 tons a year, valued at $7.2 billion, and assist the U.S. as it tries to foster a domestic electric car industry that rivals China’s. 

But Olmedo worries that when the mineral is removed from the valley, it won’t meaningfully change people’s livelihoods or their health. He points to examples in the developing world where local people have been left behind as extractive industries take what they need.

“We’re about to extract, perhaps, the world’s supply of lithium here, yet we don’t even have the simplest, the lowest of offerings, which is: Let’s build you chargers,” Olmedo said.

Chicken and egg: Too few EVs and too few chargers

Last year, electric cars were only 5% of all new cars sold in Imperial County, compared with 25% statewide. Getting chargers into low-income and rural places will become more and more important as California struggles to meet its ambitious climate targets.

The Energy Commission estimates that California will need 1.01 million chargers outside of private homes by 2030 and 2.11 million by 2035, when more than 15 million electric cars are expected on the roads. So far the state has only about 105,000 nonprivate chargers. 

Nick Nigro, founder of Atlas Public Policy, which researches the electric car market, said charging companies won’t locate chargers in regions with few electric vehicles.

“You need revenue, and if the EVs aren’t there, then your customers aren’t necessarily there, so you do have a legitimate chicken and egg problem,” Nigro said. “We have to look to public policy to help that market failure.”

The Biden administration will invest $384 million in California’s electric car infrastructure over five years. And state officials are investing almost $2 billion in grants for funding zero-emission vehicle chargers over the next four years, including some special grants in rural, inland areas for up to  $80,000 per charger.  Olmedo says the funding has been insufficient so he’s had to turn to donations and other sources of funding.

Patty Monahan, one of five members of the California Energy Commission, said “it’s particularly important that we see chargers” in the Imperial Valley and other low-income counties with poor air quality.

Imperial Valley has only four fast-charging stations open for public use, where chargers are capable of juicing batteries up to 80% in under an hour, according to the U.S. Department of Energy. Three are in El Centro, with one exclusively for Teslas; another is in the border town of Calexico and was recently installed by El Comite. Six other stations offer only slower chargers.

Olmedo envisions a network of 40 publicly accessible chargers throughout the valley. El Comite is expecting funding from the California Energy Commission, and has received donations from Waverley Streets Foundation, the United Auto Workers and General Motors. The group is seeking more state funding.

Olmedo acknowledged that he is facing a slew of challenges with his project, including some local opposition and the high cost of installation and maintenance.

At a warehouse in the city of Imperial where El Comite stores the chargers, Jose Flores, project manager for the group’s charging initiative, said he and three colleagues spent four days in Santa Ana, about 200 miles north, at a facility managed by BTC, the company that makes the chargers that El Comite is installing.

They received training on installation and maintenance techniques, and discussed how not all chargers can be used by all electric vehicles. He learned about payment and cooling systems, and that the chargers might need more frequent maintenance because of Imperial Valley’s harsh desert conditions.

“We’re like a testing ground because we have poor air quality here due to the Salton Sea and being in a desert,” he said.

El Comite installed its first charger at its Brawley headquarters in 2022. Last December, El Civico pressed ahead with a more ambitious project: Four of their fast chargers are now operating in a park in the border town of Calexico.

Chris Aldaz, 35, a U.S. Postal Service worker who lives in Calexico, charges at home, but at times uses chargers at the group’s Brawley headquarters that people can use for free. It is a Level 2, which can take several hours to charge.

“The reason why I wanted to get an EV was that it was cheaper,” Aldaz told CalMatters. “I don’t want to be spending all this money on gas, and on maintenance, and it was better for the environment.”

Nevertheless, Olmedo’s electric car chargers have become a local political issue.

Maritza Hurtado, Calexico’s ex-mayor, and coordinator of a City Council recall campaign, said it was inappropriate for El Comite to have built four electric car chargers in a downtown park. The chargers were a distraction “from our police needs and our actual community infrastructure needs,” Hurtado said at a public hearing at the county’s utility, the Imperial Irrigation District, in January. She declined to speak to CalMatters.

“We had no idea they were going to take our parkland,” Hurtado said at the hearing. “It is very upsetting and disrespectful to our community for Comite Civico to come to Calexico and take our land.”

Olmedo hopes that the chargers ultimately will be something the county’s Latino community takes pride in.

“Put this in perspective: It’s a farmworker-founded organization, an environmental justice organization, that is building the infrastructure. It’s not the lithium industry. It’s us, building it for ourselves.”

Data journalist Erica Yee contributed to this report.

This county is California’s harshest charging ‘desert’ for electric cars. Local activists want to change that  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.

Ohio has seen a big jump in the number of agency orders forcing property owners to allow oil and gas development on their land, whether they want it or not. 

The number of so-called “unitization” orders issued by the Ohio Department of Natural Resources has surged in recent years, peaking at 112 in 2022 and continuing at nearly 100 last year, according to data obtained from the agency by the Energy News Network. 

The practice is common, with rules varying by state. In Ohio, lawmakers began working to streamline the process for oil and gas companies in 2019, coinciding with a decline in the state’s gas production after a seven-year fracking boom.

Those changes run contrary to other efforts in Ohio to restrict energy development in the name of neighbors’ private property rights, including strict wind farm setbacks passed in 2014 and a 2021 law allowing counties to block new wind and solar projects.

Under Ohio law, companies must meet several conditions before initiating unitization, including a showing that at least 65% of property owners in a project area consent to drilling. 

Critics say the process was already tilted in the companies’ favor, and that the recent changes will make it even harder to block drilling or negotiate concessions.

“All the cards are stacked against us,” said Patrick Hunkler. In 2018, ODNR issued an unitization order for property he and his wife, Jean Backs, own in Belmont County, which is one of the state’s top-producing counties for oil and gas. The developer later canceled the project, so the order was revoked. More recently, Ascent Resources had tried to lease their land before backing out.  

The legal process known as unitization has been available to Ohio oil and gas companies since 1965 but was rarely used until about a decade ago, after advances in drilling technology made it profitable to tap into harder-to-develop pockets of petroleum.

“The unitization process exists to protect the rights of those … who want to lease their minerals for development,” said Rob Brundrett, president of the Ohio Oil and Gas Association, “so that a small minority of owners … cannot stop everyone else from realizing the full potential of their property and minerals.”

For petroleum companies, the process has also promoted efficient oil and gas extraction. Otherwise, reduced pressure from too many wells could reduce the total recovery from an area.

Companies must show they have consent from owners of 65% of the area above a common oil and gas deposit before they can seek a unitization order. Companies also must show they tried to reach an agreement with holdouts, and that drilling under those properties is necessary to substantially increase the amount of oil and gas recovered. Any added value must also exceed the related costs.

“Our experience at the unitization hearing was that oil and gas runs the show,” Backs said.

Hearings don’t consider environmental impacts or other reasons landowners might not want drilling and fracking. “It’s just not part of the evaluation,” said Heidi Robertson, a Cleveland State University law professor who has written about unitization. Rather, she said, the basic question is: “Will adding this land to the unit make it easier for the developer to more efficiently and more profitably get the oil and gas out of the ground?”

The answer is almost always yes. 

The Ohio Department of Natural Resources has denied only one unitization application since 2012, according to spokesperson Andy Chow. Meanwhile, it has approved more than 500 applications, with more than half the orders issued after 2020. The agency hired an additional employee in 2021 to deal with an increase in applications, Chow said.

Owners whose property is unitized won’t have pads or roads on their property, but they still get royalties and other payments. Ohio law requires “just and reasonable” compensation for landowners.

In most cases that compensation starts with a 12.5% royalty. Additional payments are adjusted for the developer’s expenses and other factors and the compensation is often smaller than that for voluntary participants. Orders typically have let companies recoup twice those amounts before unitized landowners can get payouts beyond royalties, said attorney Matthew Onest, whose firm has represented multiple landowners in oil and gas matters. 

In some cases, property owners must wait even longer. At a March 27 hearing, for example, drilling company EAP Ohio asked for a “500% penalty” for owners who did not agree to a lease. Anna Biblowitz, a negotiator for Encino Energy, claimed the higher penalty was justified by the developer’s risk and “as a motivator for other working interest owners to participate.” A ruling in the case is due this month.

Why are there more orders?

Some property owners, including Backs and Hunkler, worry about climate change and other environmental impacts. They said companies wouldn’t agree to requested lease terms for no flaring, methane monitoring and monitoring of the spring on their property.

“These oil and gas companies aren’t addressing the important issues of our environment,” Hunkler said.

Other landowners may hold out because they want more money, said Onest. “They kind of dig their heels in,” he said.

Industry experts said market forces could partially explain the rise in unitization cases. Property owners could hold out more often because they want higher payments like others got early on in the state’s fracking boom. Or, higher oil prices might be motivating companies to pursue projects that once seemed too complicated to be worthwhile. 

State officials have made the process easier, too. In 2019, lawmakers added language about how to calculate the 65% threshold, tucking the terms into a 2,600-page state budget law. Matt Hammond, who was then president of the Ohio Oil & Gas Association, told lawmakers the added language was meant to “clarify” the law. 

In practice, the change likely lowered a barrier for companies to use the tool, according to Clif Little, an Ohio State University Extension educator in Old Washington, Ohio. “If you’re seeing actually more [cases] for forced unitization, that would be a significant player in that,” Little said.

Another law passed in 2022 requires the Ohio Department of Natural Resources to hold hearings on unitization applications within 60 days. The agency must rule within 60 days of the hearing, and also let companies know in advance if an application is incomplete.

For industry, the primary benefit from the 2022 law change was to get certainty about timing. “This impacted how a producer was able to plan their drilling schedules,” said Mike Chadsey, director of external affairs for the Ohio Oil and Gas Association.

The Ohio Department of Natural Resources also changed its guidelines last year to standardize unitization applications. The agency’s website said the changes were “aimed at streamlining the review process” and that applications would include fewer documents.

Among other things, companies don’t need to file testimony from engineers, geologists and landmen in advance of hearings — something they had generally done in the past, said Robertson at Cleveland State. In her view, that further limits any dissenting landowners’ ability to prepare challenges to such testimony when the hearing does take place.

The Covid-19 pandemic also affected unitization hearings, which are now generally held via Zoom. “Allowing these meetings to be held via Zoom is a benefit to all parties involved,” Chadsey said, adding that it’s more convenient for landowners.

Folks in “suits and ties” had to come from out of state when ODNR held the unitization hearing for Hunkler and Backs’ property back in 2017. With a remote format, though, the hearing panel and company personnel “don’t have to look at you in person,” Hunkler said.

Oil and gas companies said they take every step to avoid forced leases, but that unitization is an important tool when that is not possible.

“When those means are exhausted, which often includes situations of poor record-keeping or the inability to locate an owner, unitization can be a tool to ensure property and mineral rights are realized by all stakeholders,” said Zack Arnold, president and CEO of Infinity Natural Resources.

Jackie Stewart, vice president of external affairs for Encino Energy voiced a similar position. “Encino makes every attempt to lease all landowners in each unit and only utilized unitization after all leasing efforts are exhausted, so the property rights of Ohio’s landowners can be realized,” she said.

“This isn’t something any lawyer can handle. You have to be an expert in this stuff,” Robertson said. “And all the experts are on the other side, because that’s where the money is.”

Robertson is unaware of any legislation to make matters fairer for landowners who don’t want to lease their land. And gerrymandering makes it unlikely such bills will be passed anytime soon. As she sees it, the process is “stacked against the dissenting landowner.”

As Ohio clamps down on clean energy, recent changes make it easier to force landowners to allow oil and gas drilling 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.

Virginia energy efficiency advocates anticipate a new state law will broaden and deepen energy-saving programs the state’s two largest utilities offer to customers.

The Savings Achieved Via Efficiency (SAVE) Act (SB 565/HB 746) officially became a law on April 17 during a one-day reconvened session in Richmond to consider bills the governor had amended or vetoed after the General Assembly wrapped up business in early March.

The legislation strengthens energy efficiency standards that were set to expire next year. It also renews the authority of the State Corporation Commission to approve energy efficiency programs for Dominion Energy and Appalachian Power.

The linchpin, however, is a provision directing utility regulators to develop a single, consistent test to measure the cost effectiveness of any proposed efficiency program, which can range from energy audits to weatherization upgrades to appliance rebates. Advocates called that addition a “big win.”

Republican Gov. Glenn Youngkin left that language in place but amended the bill to require regulators to also use a second test, one that’s already in existence, to evaluate any proposed efficiency programs.

Both chambers greenlighted the amended bill — the House of Delegates tally was 92-5 and the Senate’s was 37-3 — rather than risk a veto by Youngkin.

Chelsea Harnish, executive director of the Richmond-based Virginia Energy Efficiency Council, said that even with Youngkin’s amendment, the version of SAVE that emerged will boost transparency of the cost and effectiveness of both utilities’ programs.

Proponents had learned about the amendment early this month, she said.

“We are aware it’s a compromise,” Harnish said about treating the change as a speed bump instead of a roadblock. “We decided that’s something we could live with.”

Bill revamped early on 

As originally proposed by legislators in January, the SAVE Act would have created what’s called a minimum achievable floor target for each new efficiency standard. In other words, utilities would have had to meet annual savings targets scheduled to increase incrementally.

However, that language was stripped from the bill to assuage pushback from Dominion Energy and to gain bipartisan support in the House.

“That change was actually a bigger blow than the governor’s later addition,” said Mel Mackin, interim director of state policy at Ceres. “The minimum standards would have been helpful because it would have put a cost-effectiveness test in place.”

Still, even without that floor, Mackin said she is optimistic that incremental savings targets will emerge annually.

“Energy efficiency is a no-brainer for keeping costs low and minimizing waste,” she said. “It’s also a critical piece in decarbonizing the electric-power sector.”

Ceres is an advocacy organization that collaborates with the business sector to accelerate the transition to a cleaner economy. The Boston-based nonprofit had sent letters of support for the SAVE Act signed by companies such as IKEA Retail U.S., eBay Inc., Akamai Technologies and New Belgium Brewing to the governor and legislators.

The SAVE Act was a top priority for many major businesses in Virginia because energy efficiency is critical to reducing strain on the electric grid, cutting pollution and lowering utility costs for ratepayers, Mackin said.

Dominion did not respond to a request for comment.

Regulators will debut the new test in September 2025 so utilities will have plenty of time to roll out efficiency programs that comply. To design the test, they will draw on recommendations from the National Standard Practice Manual, a document devised by energy efficiency experts across the country.

What’s crucial is that the manual is an objective, technology-neutral reference tool for assessing energy efficiency investments based on eight guiding principles, Harnish said.

For advocates, the top three of those principles include the leeway to evaluate proposed energy efficiency programs by how well they align with climate goals laid out in the state’s Clean Economy Act, balance both the costs and benefits, and ensure transparency.

“Too often, utilities are putting in way more cost than benefit,” Harnish said, adding that stakeholders need to be able to review and comment on the methodologies and results of any cost-benefit analysis.

All Southeast states except Tennessee are moving toward tests that incorporate principles from the National Standard Practice Manual, she added.

SAVE start delayed until 2029

The SAVE Act’s full impact won’t kick in until 2029, even though it goes into effect this summer.

That’s because the State Corporation Commission caught lawmakers and advocates off guard by opening a docket in early January — just days before the legislative session began — to begin reviewing efficiency programs Dominion and Appalachian Power will offer for the three-year cycle beginning in 2026.

“The General Assembly looks down on trying to legislate during an open regulatory process,” Harnish said about the decision to drop 2026-28 from the realm of the SAVE Act. “We had been under the impression that docket wouldn’t be open until much later this year.”

When the new test is deployed in 2029, it will be paired with an existing test that Youngkin required with his SAVE Act amendment.

“At least he picked one of the better tests,” Harnish said. “That’s something we decided we could live with.”

Before the SAVE Act passed, Virginia law stated that regulators had to approve any efficiency program that passed three out of four cost-benefit tests.

For years, advocates have maintained that those tests — among the handful developed in California in the 1980s — are outdated ways to measure the worth of a program.

“Our issue is that they’re not transparent because you don’t know what the inputs are,” Harnish said. “When people started to analyze them, they realized that test results could look one way in Connecticut and another way in Arkansas.

“That’s what we wanted to fix with the SAVE Act.”

Another bonus folded into the new law that Youngkin didn’t touch is a measure requiring regulators to conduct studies every three years to discover where utilities are falling short with energy efficiency in their respective territories.

“There is scientific research showing utilities what they can do,” Harnish said. “The key is to find out how much in energy savings remains to be achieved among their customers.”

Under the 2020 Virginia Clean Economy Act, Dominion was required to meet energy savings reductions of 5% between 2022 and 2025. Appalachian Power, with a majority of its customers in Southwest Virginia, was directed to follow suit with a 2% reduction. The baseline for both investor-owned utilities was 2019 electricity sales.

Appalachian Power is projected to meet all of those goals, according to numbers submitted to utility regulators. It’s a different story at Dominion, which is expected to miss all of its goals or achieve only half of them. The outcome depends on whether regulators base calculations of savings on a net or gross level.

Combining the new cost-benefit test with an independent study “keeps Virginia on a path to continue to establish ambitious but achievable standards aligned with best industry practices,” said Mackin, of Ceres.

As well, she added, it’s the lowest-cost way to curb emissions of the heat-trapping gases causing climate change — which is what compelled The Nature Conservancy to back the SAVE Act.

Minimizing energy use is a key to protecting biological diversity, said Lena Lewis, the conservancy’s energy and climate manager in Virginia.

“The more we reduce energy demand, the less pollution we have,” she said, “and the easier it is to meet that smaller demand with clean, carbon-free renewable energy.”

Virginia lawmakers reached a compromise on energy efficiency – here’s what it will mean for utilities and regulators 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.

Otter Tail County, Minn.

Max Brosmer is used to spending his Saturdays starring on turf, not ice. So the starting quarterback for the University of Minnesota was recently a bit out of his element on a frozen lake three hours from the Twin Cities. 

Yet it was no accident that the Big Ten athlete ended up fishing on the ice here in February. He was paid to go. It’s part of an all-out charm offensive by Otter Tail County to introduce a new generation to rural life and, eventually, start replenishing its aging workforce. 

In the last two years, Otter Tail has paid the quarterback and five other university athletes to post online about their experiences visiting the rural county, which boasts two state parks and 1,000 lakes.

“It was unbelievable,” Brosmer said in an interview after visiting Otter Tail. “I think people are missing out on that piece of life. There’s always so much going on in the city or a busy suburb, but being able to get away from that noise is really healthy and really helpful.”

Recruiting new talent is a matter of survival for Otter Tail and other rural counties across America that face population decline, labor shortages, and widening skill gaps. 

While universities are sometimes seen as agents of brain drain, drawing away young talent who might not return, officials in Otter Tail think they can turn higher education into a catalyst for a new, long-term brain gain. 

Let the 18-year-olds go, they say, but focus on laying the groundwork for talented graduates to move there later in their careers, when they may be ready to leave city hassles behind and raise their families somewhere more rural. 

“There is one train of thought where the big university is the enemy and is stealing all our kids,” says rural rebound coordinator Erik Osberg, who led the county’s effort to strike partnerships with university athletes. “We’re saying, No, let’s find these college students, and invite them to come and experience rural life so they can form their own opinion of it.”

So far, Otter Tail has paid four football players and two volleyball players from the University of Minnesota between $500 and $5,000 each through “NIL” deals that allow college athletes to benefit from their name, image, and likeness. The NCAA changed its rules in 2021 to allow those kinds of payments.

In return, the county asks the athletes to share social media posts about their trips to the county, which have involved activities like boat rides and corn mazes. 

When Brosmer came, the county planned a visit to the local hospital, Perham Health, since the gridiron star is also a master’s student studying kinesiology who plans to pursue medicine after his football days are done. 

It surprised him, and dismantled preconceived notions. “When I was thinking of a rural hospital, I thought of a super small building, maybe not as technologically advanced,” he says. “Once I got there, it was gorgeous. A completely new hospital, in the shape of a huge canoe, absolutely unbelievable with a center center and a whole pharmacy.” 

Changing perceptions is part of the point for Osberg, who treats each tour as “legit recruiting visits,” he says. “I am trying to roll out the red carpet for them and treat them like the star talent they are.”

Back in Minneapolis, Otter Tail is working to reshape narratives, too, thanks to a multi-year marketing deal the county signed with the University of Minnesota athletics department. 

People attending a university hockey match or football game might now see the county’s Otter mascot palling around with his new university friend Goldy the Gopher. 

And it’s not just athletes who get VIP treatment. Otter Tail employers hosted a pitch competition last year at a Minneapolis brewery near campus. They also bussed 14 business students out to lake country for a few days of fishing and touring local employers. 

“If you look at the state of Minnesota, there is only one institution that produces 50,000 students a year. So if we’re trying to recruit a workforce, connecting with the largest producer of future employees is probably a good idea,” Osberg says.

To be clear, few people in Otter Tail expect that those students will immediately move to lake country upon graduation. Instead, its leaders hope that building fond associations with Otter Tail now could lead top talent to consider moving here in their thirties or forties.

Brosmer, for one, agrees the strategy could attract Gen Zers like him. “I think there’s been a shift. We’re in that period now where people in my generation are living in the cities. But as generations age, I believe it starts to fluctuate back,” he says. 

Otter Tail’s strategy is rooted in research by Ben Winchester, a rural sociologist for the University of Minnesota Extension. In recent years, he has found that the biggest growth in rural populations has come from adults aged 30 to 49. 

Mid-career professionals can help spur a rebound in rural communities, Winchester says. They bring with them education, work experience, professional contacts, and young families. 

“You just have a different priority on your life once you hit your thirties,” Winchester says. “I’m not trying to sell this to 18-year-olds. Of course, you’re going to lose some of your kids. They need to see what else is out there in the world. My point is simple: Let them go, and let them know that if they want to come home, that is fine, too.”

In Otter Tail, Osberg’s unusual job title was created as a direct response to Winchester’s research. County commissioners decided in 2018 that aggressive action was needed after a state report suggested Otter Tail could lose up to 5% of its working-age population by 2030.

A drop like that would be devastating for a community that already had trouble filling key positions at its medical facilities and manufacturing companies, from smaller machine and auto repair shops to bigger food processing factories. 

“That was the lightning bolt for our county commissioners to say that we needed to do something,” says Amy Baldwin, who serves as the county’s community development director.

Otter Tail treats tourism as a “first date” for wooing potential new residents. The community college hosts art exhibits and plays, while its lakes are dotted with large statues of otters, loons, and other critters. 

Community-led festivals, like “Froze Fest,” paint an idyllic portrait of life in rural Minnesota. It’s an image Osberg reinforces by regularly sharing photos of sunsets and trophy fish on Instagram, as well as video interviews with urban transplants who have relocated to Otter Tail.

Still, all of that work is wasted if Otter Tail can’t create the infrastructure to support new residents once they come. “Attracting people with the marketing and the lifestyle doesn’t matter if they don’t have childcare, broadband, jobs, or a place to live,” says Baldwin, who moved her husband and kids from Minneapolis to Fergus Falls seeking a better quality of life over a decade ago, and is now charged with making sure others can do the same.

While Otter Tail’s natural beauty is one of its strengths, its many lakes have made expanding broadband access particularly expensive. The county has improved from its bottom-place ranking in recent years, but still ranks 69th out of 87 counties in connectivity.

Affordable housing is tough to come by, with median house sales prices in Otter Tail at around $303,000 in March, up 33% year-over-year, according to Redfin. That’s made the task of bringing in new workers even more difficult, Winchester says: “The line is around the block for people wanting to move to our rural areas. We just can’t find anywhere for them to live.”

It doesn’t help, county officials say, that a third of the county’s houses are summer homes, which families may hold onto for generations. Construction costs have risen so high that it doesn’t make sense for private companies to build new entry-level homes. That’s forced the county to step in: It’s starting by building six new homes, even though administrators know it might not be a long-term solution since they will likely have to sell each for a loss of $50K to $100K. 

Still, Otter Tail has made some progress in adding childcare options, enlisting churches and employers to provide facilities that can pass state regulations that became stricter in recent years. Plus, the existing workforce gaps mean there are plenty of high-paying careers available for transplants willing to move to small towns like Perham, where there are far more jobs than people to work them. 

In fact, across rural America, half of adults now have a job that pays at least middle-class wages, according to a recent Georgetown University report. That’s just a few percentage points below the 54% that do in urban areas, despite the perception that there are fewer opportunities outside the cities. 

Osberg says that one of the most important ways rural communities can try to engineer their own growth is to shift their own narratives. 

“Part of it is about getting rid of the negative self-talk: Nobody is going to move to your area because they feel sorry for you,” Osberg says. “Imagine if you were a football coach, and you told a recruit that the field is terrible, the facilities suck, and your players are awful. Do you think that athlete would still want to come?”

At the very least, Otter Tail’s efforts are keeping disaster at bay. The county’s percentage of working age adults has remained steady, a win for now, considering the decline that was predicted half a decade ago. 

And there are glimmers of hope, coming from a new generation. Melani Shaffmaster, an All-Big Ten setter on the University of Minnesota’s volleyball team, has been asking about local summer internships since she visited last fall. “Found my inner otter,” the accounting and finance major posted on Instagram, smiling in front of a mural of lakes and loons.

This story was co-published by USA Today.

The post To spur a rural rebound, one Minnesota county is paying college athletes to promote it  appeared first on Open Campus.

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.

An Illinois bill that started as a protection for solar-powered doorbells has developed into comprehensive proposed legislation to break down the barriers confronting rural electric cooperative members seeking to install solar. 

Many residents and solar developers say the measure is sorely needed, since electric cooperative members often face arbitrary and changing interconnection, compensation and liability policies from the cooperatives. 

Illinois HB5315, called a “Solar Bill of Rights” and introduced Feb. 29, would require the state’s more than 50 cooperatives and municipal utilities to allow net metering until a certain threshold of solar penetration is met, and develop “shared policy” on solar that must be approved by the Illinois Commerce Commission.

The bill would prohibit problematic requirements often reported by electric cooperative members, including complicated insurance requirements, lengthy interconnection processes and restrictions on system size, solar leases and power purchase agreements. People with solar would also continue under the same billing terms for 25 years after installing systems. 

“Customers of municipal electric utility systems and rural electric cooperatives often do not have the same opportunities as customers of investor-owned utilities” to get solar, says the bill. 

Scott Allen, renewable energy policy coordinator for the Citizens Utility Board, said the organization tends to get more calls about solar problems from electric cooperative members than customers of the two investor-owned-utilities that serve the majority of the state’s population.  

“Members aren’t satisfied with their rates of compensation, the cost of engineering studies, and the fact that policies can change with little or no notice,” Allen said. “Many people invest in solar, and sign net metering agreements with a pretty good idea of how long it will take to recover their costs, then the policy changes, and their financial outlook changes dramatically. Members don’t have a clear understanding of how, or to whom they address their concerns. Often, the rules about addressing the [electric cooperative] board are unclear, and in some cases, it can take months to get a few minutes on the agenda.”

The 2021 Climate & Equitable Jobs Act (CEJA) required electric cooperatives to interconnect rooftop solar installations, but the cooperatives still institute size limits, requirements for expensive liability insurance and other barriers, critics say.

Electric cooperatives and municipal utilities are not regulated by the Illinois Commerce Commission in the same way it oversees investor-owned utilities ComEd and Ameren. The cooperatives were started as ways for rural residents to run their own electric systems democratically. But critics say the boards that administer the cooperatives often lack meaningful public input procedures, and have not made adequate efforts to embrace the clean energy economy. Proponents of cooperatives and municipal utilities meanwhile note that they offer citizens more direct control, at least theoretically, than investor-owned utilities, without a profit motive.

Allen emphasized the bill “is not about removing local control from any units of local government, it’s about making sure consumers are protected.” 

“We’re trying to adopt a universal or semi universal standard for everybody across the state, where we have 30-plus municipal utilities, 25-26 distribution cooperatives, and they each have different policies, different ways they compensate their customers, and these policies can change whenever the board or city council wants to make that change,” he said. “It’s caused a lot of problems for individuals who got their system sized and financed based on one set of information, and the next year that information changes.”

The Association of Illinois Electric Cooperatives did not respond to requests for comment. Especially given potential pushback from electric cooperative interests, the bill may be unlikely to pass during the legislative session that ends May 24, in which case it would likely be reintroduced next year. 

A ‘muddy’ situation 

After Meredith Barnes and her husband purchased a home and started a lavender farm in central Illinois, they hoped to install solar. The Eastern Illini Electric Cooperative closed its net metering program in July 2020 after solar reached 5% of its load, with 250 households out of about 13,500 having solar. So Barnes and her husband — who installed their array last year — receive only a low flat rate known as “excess electricity value” for power they send back to the grid.

Barnes noted that the flat rate is set annually, so households with solar don’t benefit if electricity prices rise, theoretically making solar more valuable. And the rate is much lower than the retail rate that cooperative members with net metering would get.

The bill would allow cooperatives to cap net metering at a set threshold, but the Illinois Commerce Commission would approve a “fair value of solar” that cooperatives and municipal utilities would be expected to offer through other billing structures. 

“The equitable value of solar is definitely not what they’re paying us,” Barnes said. “They say [the flat rate] will go up, but when?  There should be a minimum standard [paid for solar] across the state.”

Barnes said she’s had difficulty communicating with cooperative board members and understanding how the flat rate is set. Such lack of transparency is a common complaint among electric cooperatives, consumer and solar advocates say.

“The flat rate is very muddy. It’s just weird,” Barnes said. “The cooperative doesn’t like when you try to talk to them about it.”

The Eastern Illini Electric Cooperative did not respond to a request for comment.

Barnes tries to use as much of the electricity from her array as possible. “Since I have a farm and work from home, I can do laundry during the day, I can run the dishwasher during the day,” she said. “For someone who works at an office from 8 to 5, that’s not possible.” 

Buying a battery to store their own energy was too expensive, she added.

“What we did is bought an electric vehicle and we only charge it when it’s sunny. It’s like our battery, I’m not sending as much back to the grid because I’m going to store it in my vehicle.” 

The Solar Bill of Rights legislation does not address net metering or other policies for the state’s two investor-owned utilities, ComEd and Ameren, whose rates are determined in proceedings before the Illinois Commerce Commission. These utilities will end net metering in 2025, replacing it with a rebate for solar systems.

“We don’t want to compare investor-owned utilities to cooperatives,” said Allen. “There is an argument to be made that Ameren and ComEd have quite a bit more solar installed in their territories, they’ve kind of reached a decent threshold, whereas municipal utilities and cooperatives are lagging behind.” 

Humble beginnings

When state Rep. Daniel Didech (D-59) and supporters began drafting the bill, it was meant to make sure that municipalities and counties couldn’t ban small solar collectors on the fronts of homes meant to power smart doorbells or other appliances. That language, still in the bill, expanded to ensure that these government bodies can’t ban solar arrays more generally. (The bill does not apply to shared roofs or buildings over 60 feet tall.) 

A state law already bans homeowners associations from restricting solar for aesthetic or other reasons. But some Illinoisans still face restrictions from local government agencies. That was the case in the Chicago suburb of Sugar Grove until a village board meeting on April 16. There, board members overturned a ban on solar on front-facing rooftops, thanks to an energetic campaign by homeowners Becky Brocker and Mike Rayburn. 

Advocates and solar developers say municipal restrictions like Sugar Grove had are actually rare. The only other well-known case is Kildeer, Illinois, which removed a total ban on solar in February and still prohibits front-facing arrays. But, advocates said, it’s still important to codify the right to solar statewide, especially as official opposition may arise more frequently as more and more people install solar. 

“When [Didech] expanded the bill, he was thinking ahead that these sorts of covenants exist in places we don’t know about yet, just trying to get out ahead of any units of local government that might catch on to, ‘Hey, we can restrict solar for whatever reason we want to,’” said Allen.

John Delurey, deputy program director of the organization Vote Solar, noted that more than 75,000 small solar arrays have been installed statewide since the 2017 Future Energy Jobs Act created incentives. But preventing any future barriers to solar, and smoothing the way in electric cooperative territory, is crucial to make sure that growth continues, he said.

“In rural areas, counties may be the bodies with jurisdiction. I’m sure there are still people in Illinois having trouble because one person on a zoning committee doesn’t like solar,” said Delurey. “It drains everybody’s resources to roam around and play whack-a-mole with all these different rules.”

Illinois rural electric co-op customers seek clarity, consistency from ‘Solar Bill of Rights’ 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.

This is the sixth installment of Barn Raiser’s 2024 election coverage series “Charting a Path of Rural Progress,” which features interviews with rural policy experts and organizers who came together in Omaha, Nebraska, in 2023 to forge a rural policy platform on which candidates can run—and to which voters can hold their elected leaders accountable. The platform that grew out of that Omaha meeting, A Roadmap for Rural Progress: 2023 Rural Policy Action Report, released last October, details 27 legislative priorities for rural and small town America, based on legislation that has already been introduced in Congress.

Erik Hatlestad, 33, works on rural energy issues with the Minnesota nonprofit CURE (Clean Up the River Environment) as their Energy Democracy Program Director. Founded in 1992, CURE describes itself as a rural-focused environmental group “rooted in the movement for rural social justice.” The group’s 12 employees are scattered in small towns across the state.

Hatlestad is currently on a six-month stint with the U.S. Department of Agriculture’s Rural Utilities Service (RUS) as a Clean Energy Benefits Advisor, where he leads the Empowering Rural America (New ERA) program, a historic investment in rural electrification that is based, in part, on Hatlestad’s 2019 report, “Rural Electrification 2.0: The Transition to a Clean Energy Economy,” which outlines the role of rural electric cooperatives in the transition to clean energy in rural America.

Hatlestad, grew up with two brothers on a small family farm, growing corn and soybeans, about 10 miles from New London, Minnesota (population 1,252), in Kandiyohi County, where he now lives.

How did you get into rural political activism?

I grew up shortly after the farm crisis of the 1970s and 80s, which shaped the hollowing out of rural communities that we’re still seeing today. We saw the end of several of our local farm cooperatives in New London and western Minnesota, because all of the members had been driven out of business.

Fighting for rural communities to regain control over their own future—a future that has been taken from them by exploitative markets and large agribusiness—is  personally important to me. And I like to continue that historic legacy of the agrarian movement from yesteryear.

I’m very, very committed to rural democracy and building democratic solutions for small towns. I’m involved with a number of community projects in New London I’ve helped run the community theater and cocktail bar, and just helped opened a food cooperative, which will be the first grocery store in our town for the last 15 years. I serve on a lot of different boards and am very involved with Farmers Union and was until recently on the board of the city council.

How does the Rural Policy Action Report address the challenges rural America faces?

The biggest problem is that rural America has faced underinvestment and disinvestment for so long.

In previous decades, we had strong rural social movements that fought for these big investments, like the original Rural Electrification Act and the New Deal, and all of these incredible programs that helped make rural America what it is—or what people like to think they remember it as. Those social movements and organizations were crushed during the 1980s farm crisis and as a part of deindustrialization, such as with NAFTA and the offshoring of manufacturing jobs, and the right-wing attack on organized labor. As a result, rural social movements haven’t had the political strength to put forward the alternative solutions that were historically offered to rural people to win new investments in their communities.

What the Rural Democracy Initiative—the group that sponsored the Omaha summit out of which came the Rural Policy Action Report—has done is bring momentum back to rural social movements by offering an alternative to the disinvestment and the race to the bottom and what has been the essential hollowing out of rural communities.

The Rural Policy Action Summit was held in Omaha, Nebraska, which is where the Populist Party held its first convention back in 1892. Is that ancient history?

For all of us who are involved in creating a progressive future for rural America, there isn’t a day that goes by where we don’t think about these historic social movements and what they were able to accomplish in the same communities we live in today.

For those of us in rural Minnesota and the Dakotas, we love to think about the Nonpartisan League and the Farmer-Labor Party and how they transformed the states by gaining political power—creating state grain elevators, and in North Dakota, creating the country’s only state-owned bank. And the incredible progress that was made by farmer labor governors in Minnesota.

There’s a common thread among all of them, starting back with National Grange of the Order of Patrons of Husbandry beginning in 1867 and flowing into movements that would become the Populist Party [People’s Party] and the Progressive Party. We look to them as inspiration for what we’re doing today.

The co-operative movement was really born in Minnesota. The congressman (Andrew Volstead) who co-wrote the Capper Volstead Act, which legalized co-ops in 1922, was from Granite Falls, Minnesota. Some people call it the Magna Carta of cooperatives in the U.S. The first electric co-op in the country was the Stony Run Light and Power Company, which was just south of Granite Falls, near CURE’s offices. It’s a history that is barely outside of living memory, but it’s certainly something that we think about on a daily basis.

How would a transition to clean energy affect rural communities and the rural electrical cooperatives of which 42 million Americans are members of?

A few years ago, I was one of the authors of a white paper called Rural Electrification 2.0, where we took a look at the historic and systemic barriers holding up the clean energy transition in electric cooperatives and we made some of the policy recommendations in that report.

Since then, we have been working to build support for an investment in rural electrification to clear the way for the clean energy transition, and part of that work has been through the Rural Policy Summit in Omaha and the resulting Rural Policy Action Report.

Many organizations, including National Farmers Union, Sierra Club and the National Rural Electric Cooperative Association themselves have all come around to the concepts that we put forth in Rural Electrification 2.0. Reinvestment in rural electric co-ops was one of the key programs that the Biden administration listed in their rural investments portfolio when they took office. Our programs made it through every single edition of Build Back Better and were eventually passed in the Inflation Reduction Act and the implementation process has begun over the past year. Those programs are now known as Empowering Rural America, or New ERA, and the Powering Affordable Clean Energy Program, or PACE.

How accessible is the program? I heard that the application process can be a daunting for individual rural electric cooperatives.

There is an urgent need to get the program money out the door before potential cuts could be made to the program by Congress. The U.S. hasn’t done a major investment in rural electrification like this since the 1930s. So co-op staff and board members and the communities themselves aren’t accustomed to thinking as big as they’ve been given the opportunity to now. It has been problematic for rural utilities and rural communities to pursue federal grants at the same level as communities that are better resourced.

Having spent some time in small town government on city council myself, I understand how staff are already overworked and underpaid. It’s tough to ask people in similar positions, whether it’s an electric co-op or a small town team, to take on a robust federal grant making process.

So there are some challenges. But the response that co-ops gave to these programs is overwhelming. The programs have received over 140 applications from the 40 states, and there are about 900 rural electric co-ops, and they are only active in 46 states. But a number of these applications represent coalitions of co-ops or generation transmission co-ops applying on behalf of their distribution members. So we can credibly say that half of all co-ops in the country showed interest in this program.

You dated the start of the rural decline back to the farm crisis of the 1970s and 80s. Why do you date it back to then? Some people say it begins back with Earl Butz in the early 1970s when he was secretary of agriculture under Nixon and told farmers to “get big or get out.”

I would generally agree that it started with Butz and agribusiness companies and the fertilizer industry essentially concluding that the best way to protect their own profitability was to make sure that farms got bigger and bigger and bigger. It’s a historic arc similar to the attack on organized labor that happened over the last half of the 20th century, which you could summarize that as being a coordinated attack on the New Deal coalition by business interests and their political allies.

It started with Butz and the encouragement of bigger and bigger farms and culminated in the 1970s and 80s with the farm crisis, and dealt one of the finishing blows to the agricultural system of family farming, which had been a solid political block organized around the co-operative principles of the cooperative movement. You see similar kind of tropes play out with the deindustrialization in the Rust Belt, the consolidation of bigger businesses and the promotion of free trade.

Did you did your county vote for Donald Trump?

Oh, yes.

How do you think about bridging political divides within your county and rural America in general?

You don’t bridge some of those divides, you provide an alternative. For too long, people who would not call themselves Republicans have not had the ability to articulate any kind of alternative. Democrats have spent too long trying to say, “We’re just the same, we’re just not so scary.” That is part of the problem we face here: no one has provided an alternative.

People in rural communities feel—and I would certainly count a lot of Trump supporters in this as well—totally ignored. If I’m accustomed to, as a rural community, being ignored and being disinvested from, and I don’t have the kind of political institutions that used to exist, well, I’m just going to do the thing that makes the people who I know are making my life worse as mad as possible: I’m going to vote for the most insane person. I’m not going to be heard anyway, so why should I seriously participate in the process?

We need to provide an alternative that we can articulate that resonates with people. Like the Ohio referendum on abortion on November 7, for instance. Strong progress was made in a lot of rural communities in Ohio, thanks in part to organizers who were putting an alternative out there and actively talking to people.

It’s about helping rural people feel comfortable expressing the views that they have, because so many people in these places feel isolated. There’s certainly a social aspect to that, too, but it’s also a product of decades of disinvestment and disenfranchisement. Attempts to rebuild those historic political institutions around progressive policy ideals are predicated on presenting such alternatives.

Why do you think the Democratic Party has for so many years failed in that?

A lot of people struggle with that question, and I do as well. There hasn’t been much political leadership in the party coming from rural parts of the country. In part, the party has been disconnected from these communities because the people who would participate in these movements have left rural areas.  And part of it is the acquiescence of some Democratic Party leaders to mirror their opposition and buy into the ideas of so-called free trade, which has accelerated the decline and disinvestment in rural communities.

A summary answer would be: the Democratic Party’s loss of soul, the loss of its identity as an institution.

The post Electrifying Democracy in Rural America appeared first on Barn Raiser.

A pair of cousins who want to lease land for a contested solar project in central Ohio say a vocal minority is trying to interfere with their property rights.

“I have rights as an owner, farmer and investor that shouldn’t be limited by a small group of individuals who are opposed to any solar development,” said Richard Piar. He and Ethan Robertson jointly own two parcels of property in Knox County, which they want to lease to developer Open Road Renewables for the proposed 120 megawatt Frasier Solar project.

Much of the public debate surrounding the project has pitted local groups that oppose solar energy on agricultural land against the developer and clean energy advocates. But for the cousins, the project is a way to bring in new revenue and help keep the land in the fourth-generation farm family. 

“Solar gives my family opportunities it otherwise would not have for a financial future,” Piar said.

Robertson is now seeking to intervene in the Ohio Power Siting Board case that will decide the project’s fate, and the cousins recently shared with Energy News Network how the project is important to them and their property rights.

“When someone who is not a farmer can tell us farmers what we can do with our land, it creates a slippery slope for property rights,” Piar said.

Concerns about conservation also factored into the cousins’ decision to lease the land, which the solar farm will have to restore at the end of the project. In Robertson’s view, those terms counter opponents’ arguments about blocking the project to protect farmland, especially when much of it – on the outskirts of Mount Vernon in Clinton and Miller townships, about an hour’s drive from Columbus – could otherwise become residential subdivisions.

“My children are nine, seven and five years old. This project is a key way to protect our land from the many ways this county may change over the next four decades,” Robertson said.

And much of the land in the Frasier Solar project will still be used for agricultural purposes while the solar project is in operation. On March 8, Open Road Renewables and New Slate Land Management announced they signed a letter of intent to use sheep grazing to manage vegetation for the project.

Brad Carothers, who runs New Slate, lives in Knox County and raises Katahdin sheep. When a letter came from Open Road Renewables about the Frasier Solar project, he reached out to the company.

“One of the main issues new and emerging farmers face is access to land,” Carothers said. “We’re a first-generation business. And so land is not something that I have from previous generations to utilize. And so this is how we can expand our business.”

Why zoning isn’t the issue

Under Ohio law, a landowner generally gets to control who has access to real property and how it is used, including the right to lease it to others. Zoning can restrict some uses to certain areas, such as industrial or commercial activities. 

For electric generation facilities, however, state law and rulings of the power siting board generally take precedence, except as provided in Senate Bill 52, said Jacob Bryce Elkin, one of Robertson’s lawyers who is with the Renewable Energy Legal Defense Initiative at Columbia Law School’s Sabin Center for Climate Change Law.

The 2021 law lets counties ban solar projects from parts of their territory, but only if they were not already in the grid operator’s queue when the law became effective. 

“Frasier Solar clearly fits the bill to be grandfathered” under that exception, wrote Ohio Rep. Bill Seitz in a Feb. 23 letter urging the Ohio Power Siting Board to approve the project. Under the law, one county and one township representative will serve as ad hoc board members on the case.

Elkin also noted that while the Knox County Commissioners decided to ban wind farms in 2022, the same resolution said they would allow large solar facilities. So, because of SB 52, “if the OPSB grants the approval for the project, there’s nothing in local law that prohibits this project from being developed,” he said.

Yet when Knox Smart Development, an anonymously funded group opposing the solar project, hosted a program last month, speakers there talked about zoning and hypothetical situations that don’t apply to the solar farm case.

“For anybody preaching property rights, I always just like to ask them flat out: Does that mean you want to just ban or abolish all zoning?” said Jared Yost, a Mount Vernon resident who incorporated the group. Surely, he suggested at the Feb. 24 event, landowners wouldn’t want a chemical plant going in next door or sewage flowing into their yards.

Kevon Martis, a frequent opponent of renewable energy projects, took a similar tack, suggesting no one would want a 24-hour truck stop or adult bookstore next door – uses already governed by local zoning rules. 

“Everybody says, ‘I should be able to do what I want on my private property,’” Martis said. “And while they may mean that about them, they never mean that about their neighbors.”

A company official with Open Road Renewables was denied entry to the group’s Nov. 30 “town hall meeting” on the project. The group’s events have also denigrated the perspective of farmers and other landowners who will benefit from solar.

“In this project and a lot of projects like this, it’s easy for the supporters of the project to have their voices drowned out by a vocal minority of people opposing the project,” Elkin said.

Even aside from SB 52, zoning doesn’t let governments arbitrarily limit people’s use of their property, Elkin said. Instead, it needs to be rationally related to legitimate land use concerns.

“The onus is really on the opponents to put forward a case that’s grounded in fact, and they haven’t done that,” Elkin said.

What about the neighbors?

Filings by Preserve Knox County and Knox Smart Development in the Ohio Power Siting Board case claim the Frasier Solar project could interfere with adjacent owners’ property rights. And Robert Bryce, a former fellow with the Manhattan Institute, which has been linked to fossil fuel interests, claimed it was “BS” to think solar projects wouldn’t hurt property values in an area.

Among other things, Bryce cited a 2023 study in the journal Energy Policy by researchers at Lawrence Berkeley National Laboratory and the University of Connecticut. The study team’s analysis of 1.8 million real estate transactions found, on average, a 1.5% impact on sale prices for homes within half a mile of a solar project.

However, data for the study ranged from 2003 through 2020, which wouldn’t necessarily reflect the current real estate market. The study also didn’t compare the effects on property values near projects with or without measures to prevent potential negative impacts, although the authors did note that developers or policymakers have various tools to employ, such as landscape measures or compensation for neighbors.

The Ohio Power Siting Board revised its rules for solar farms after the Berkeley Lab study came out. The rule changes require setbacks from property lines, homes and roads. The rules also call for “aesthetically fitting” fencing and other requirements.

Open Road Renewables also stressed steps it takes to accommodate nearby landowners.

“We offer good neighbor agreements at all of our solar projects, and they generally include some sort of compensation,” said Craig Adair, the company’s vice president for development. Payments compensate for periodic disturbances during construction, while also letting neighbors benefit financially from the project, he explained.

Payments also encourage many neighbors to cooperate by sharing drainage tile information. That helps the company protect against problems with drainage or even improve local conditions, said Open Road president Cyrus Tashakori.

Robertson, Piar and other potential lessors are not alone when it comes to valuing property rights in Knox County.

Resident Steve Rex said he attended a Knox Smart Development meeting, which he felt was one-sided and presented inaccurate claims. Property owners shouldn’t have to worry about what other people think about how they use their land, he noted.

Franklin Brown, another Knox County resident, took exception to solar opponents trying to limit the rights of property owners for the Frasier Solar project. “The same conservative people say, ‘Well, we don’t want government up in our faces,’” Brown said. “But oh, here they do?”

The Ohio Power Siting Board is supposed to use statutory factors to decide whether a project moves ahead, rather than the number of supporters or opponents. However, the board has referred to local opposition in some past decisions blocking solar projects. The board will hold a public hearing on the Frasier Solar Project on April 4 at the Knox Memorial Theatre in Mount Vernon. The evidentiary hearing is currently scheduled for April 29.

Ohio landowners say solar opposition groups threaten their property rights 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.

Overnight in early July last year, Vermont solar installer Bill Chidsey got a call that a grocery store he worked with in his village of Hardwick was flooded. He arrived to find feet of water in the Buffalo Mountain Market’s utility room, spilling over from the rising Lamoille River in a record-breaking rainstorm. 

“The grocery store survived by an inch,” Chidsey said. “If it had rained fifteen more minutes, they’d have lost four compressors.” 

He’s now helping the co-op build a net-zero energy system that will use solar power and recycled waste heat from the store’s refrigerators. But it’s going to be a long project — just one of countless examples Vermont has seen since last year of how sustainable rebuilds in the wake of a flood don’t happen quickly. 

“I think we’re just getting started with this,” Chidsey said. 

Advocates, utilities and state agencies have seen slow progress and mixed success since July 2023 in trying to replace flood-damaged home and business energy systems with more efficient, cost-effective, low-carbon technology. Now, they hope to redouble these efforts as part of a long-term recovery — both to keep people affected last year from falling through the cracks, and to be more resilient in the next storm.

“We consider that we’re now about to start ‘phase two,’ where we hope to go back and talk about energy systems,” said Sue Minter, who leads Capstone Community Action in central Vermont. “In the emergency — with winter and nowhere else to go, and oh, by the way, no contractors available, labor shortage, material shortage, crisis — we couldn’t do the transition work, but that doesn’t mean we won’t.” 

Lessons from storm Irene

More than a decade ago, Minter was the deputy secretary of Vermont’s Agency of Transportation when the 2011 Tropical Storm Irene — comparable in its severity to the 2023 floods — washed out hundreds of miles of roads and bridges across the state. 

As the state’s Irene Recovery Officer, Minter spent the next two-plus years grappling with federal regulators and pushing through new policies and programs to rebuild “stronger, with resilience in mind,” she said. This included allowing easier upsizing of culverts and clearing development out of floodplains. 

Many places with these post-Irene resilience upgrades and reforms saw less damage in the July 2023 floods as a result, Minter said. Vermont officials even came to a recent meeting of the Maine Climate Council, after a pair of weather disasters there, to talk about their approach to flood-resilient infrastructure.  

“When you know you’re in an emergency, and you know everything has been destroyed, you also know it’s an opportunity to innovate … to rebuild differently,” Minter said. 

Vermont, often called a potential haven for future climate migrants, is nonetheless seeing more frequent and intense rain and floods as one of its top impacts from human-caused climate change. The state also relies heavily on pricey, carbon-intensive heating oil. 

After last year’s floods, Vermont leaders wanted to seize the moment to help affected residents make future-looking energy and efficiency upgrades on a widespread scale. 

“They’re ripping out drywall, they’re having to update systems — this is the time to make sure that you do it properly,” said Efficiency Vermont supply chain engagement manager Steve Casey.

Making emergency rebates accessible

Efficiency Vermont created an emergency flood rebate program for affected homeowners and renters, reallocating $10 million in pandemic aid already set aside for low-income weatherization projects.

The new program offered up to $10,000 per household to repair or replace flood-damaged energy systems and other appliances, on top of existing funding for efficient electric heat pump water heaters and electrical panel upgrades. Similar rebates for damaged businesses were just raised to a $16,000 cap. 

But uptake on this funding has been slow. As of January, only 155 households had received flood rebates of $5,100 apiece on average, according to state legislative testimony from Efficiency Vermont director Peter Walke.

It’s partly because the initial $10 million was “an overshoot to ensure we wouldn’t run out of funds,” allocated quickly “without knowing what the actual need would be,” said spokesperson Matthew Smith. 

But people also ran into myriad barriers to using the money quickly. 

Some lacked up-front cash to pay for upgrades that would be rebated later. In response, the state has begun offering a 100% cost-coverage program for the lowest-income clients, where contractors are paid directly by the state. That program had paid out nearly $92,000 to 10 people as of January, per Walke’s testimony, with 58 more in the pipeline. 

“The households that are still in significant need at this stage were vulnerable households to begin with,” Casey said. “We do have this repeating situation where flood events kind of just exacerbate some vulnerabilities for certain households.” 

‘Life and safety first’

The timing of the 2023 floods was another complicating factor. The upcoming heating season loomed in the months after the disaster, and limited housing stock meant people couldn’t relocate from damaged homes, unlike after Tropical Storm Irene, said Sue Minter.

“In 2023, July, people had to get into their homes as quickly as possible,” she said. “You always have to have life and safety first.” 

The repairs and retrofits needed most urgently were not simple. Many people’s water and space heating systems and electrical panels were in basements, “the first place to flood,” said Casey. 

Parts of Vermont are trying to change this norm — Waterbury, for example, requires basements to be above flood elevation in new or substantially improved home construction, among other flood protections. 

Chidsey, the solar installer in Hardwick, said he and his electrician have tried to shift to putting electrical panels on the outside of homes, with any indoor subpanels out of the basement. Ideally, he said, the cellar becomes “just a hole in the ground that holds up the house, because water comes in often now.” 

But moving HVAC infrastructure out of a vulnerable basement, whether to meet a local requirement or voluntarily, isn’t easy, especially after major damage, Casey said. People may not have a ready space for that equipment on the first floor, or may need mold remediation before taking on serious flood-proofing. 

It means that the advocates working to facilitate upgrades have had to take a long view.

‘The promise that we’ll be back’

Last fall, Efficiency Vermont, Capstone, the state’s utilities and a range of other partners stood up a new system of Vermont Energy Recovery Teams, who went into damaged homes to help people plan and prioritize repairs before winter, including coordinating holistically across contractors and funding sources. 

Some homes were able to switch straight to heat pumps as a cheaper, cleaner method of water and space heating, officials said. But for many, a replacement oil or gas system was the simplest short-term option. 

Efficiency Vermont does not normally offer incentives for installing fossil fuel systems, but made exceptions for high-efficiency Energy Star-rated models as part of its flood recovery rebate program.

“In every case, we looked for something that was more efficient than what they had before,” said Vermont Gas energy innovation director Richard Donnelly, who was part of many recovery team home visits. 

In each of those visits, the teams would take note of residents’ long-term needs and goals for decarbonization, resilience, comfort and lower energy burdens, with an emphasis on heat pumps. 

“We left off with sort of the promise that we’ll be back,” said Vermont Gas CEO Neale Lunderville — that “there’s money available for some of these technologies, that we can help you with the same process.” 

The recovery teams are now under the umbrella of GreenSavingSmart, a pilot energy and financial coaching program for low-income residents run by the Vermont Community Action Partnership. They’ll soon begin revisiting last fall’s clients to facilitate a new round of resilient improvements. 

“In the grand scheme of things, it’s a hopeful pathway to allow these households to have — once they’re fully made whole and recovered from all of this — a lower energy burden and cost burden than the situation they were in to begin with,” said Steve Spatz, an account manager on the supply chain team at Efficiency Vermont. “It really is an opportunity to … upgrade the conditions for the household.”

Months after devastating floods, Vermont renews efforts to aid climate-friendly rebuilds 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.