Back
SOLAR: Wyoming regulators greenlight a proposed 771 MW solar-plus-storage facility on private land near Cheyenne. (Casper Star-Tribune)
ALSO:
OVERSIGHT: Arizona residents push back after a county approves a proposed natural gas peaker plant next to a retirement community shortly after banning new utility-scale solar installations. (Guardian)
CLEAN ENERGY: The U.S. Energy Department awards over $2 million to community groups and nonprofits to fund clean energy projects, including ones in six Western states. (news release)
TRANSPORTATION: Colorado lawmakers pass legislation aimed at expediting proposed passenger rail service between Denver and coal transition communities in the western part of the state. (Colorado Newsline)
GRID: Colorado Gov. Jared Polis signs legislation requiring utilities to update their distribution grids to support state electrification and decarbonization goals. (news release)
OIL & GAS:
CLIMATE:
COAL: Right-wing Wyoming lawmakers call on Gov. Mark Gordon to sue the Biden administration over its proposal to halt new federal coal leases in the Powder River Basin. (Cowboy State Daily)
LITHIUM:
Duke Energy is already under fire in North Carolina for its plan to blow off a state deadline to curb carbon pollution while also building a massive new fleet of fossil fuel plants.
Now, the company’s blueprint is locked on a collision course with fresh rules from the Biden administration, which target coal and new natural gas plants and take effect in eight years.
“Duke is going to have to go back to the drawing board,” said David Neal, senior attorney with the Southern Environmental Law Center, “and come up with an alternative that is compliant with the rules.”
While much focus on the long-awaited Biden rules has centered on coal, their impact on natural gas is arguably more significant. Duke isn’t alone among American utilities in being forced to re-examine long-term generation plans as a result.
“We think it’s important for every utility and every commission to take a step back,” said Amanda Levin, director of policy analysis with the Natural Resources Defense Council.
But even as the federal regulations underscore a law unique to the state, it’s not clear if North Carolina regulators will take a beat – or even if there’s time for them to corral Duke and an array of stakeholders to rework, vet, and approve a new carbon reduction and long-range plan due by the end of the year. That’s why many advocates say debate over the utility’s immediate next steps will be crucial.
“It’s going to be important to adopt a near-term action plan that really is ‘least regrets,’” said Neal, who’s representing numerous clean energy groups in the proceeding on Duke’s generation plans. “The new rules just put further emphasis on what we already knew was true: we’re going to have to accelerate the adoption of clean resources.”
Duke’s existing fleet of natural gas-fired plants aren’t affected by the new Biden rules. Nor are the smaller gas plants Duke proposes to occasionally satisfy peak demand and serve other limited roles on the electric grid.
But the company plans at least five large, combined-cycle plants in the Carolinas that are impacted by the rules. The four projected for North Carolina include a 1,360-megawatt plant in Roxboro, about an hour north of Durham, for which state regulators are now weighing a permit application.
Natural gas is a fossil fuel, but Duke deems the Roxboro plant and others like it essential to the zero-carbon electricity future that state law mandates by 2050. These baseload generators can back up sources like wind and solar to ensure reliability. At the point of combustion, they produce about half the carbon pollution of coal. And in theory, hydrogen molecules separated from chemical compounds could ultimately supplant gas as a fuel, bringing the plants’ carbon emissions down to almost nothing.
“Natural gas is available 24/7 — with fewer emissions than coal and at a lower cost than renewables alone,” Duke said on its website this year, around the time it asked regulators for permission to build the Roxboro plant. “The new [Roxboro] units would be designed to operate on carbon-free hydrogen in the future.”
But critics say this rationale is flawed in virtually every respect. The cost of natural gas is on the rise, and one recent study showed it was a major driver of recent Duke rate hikes in parts of North Carolina. In December 2022 during Winter Storm Elliott, gas plants failed when they were needed most — in the wee, frigid hours before the sun rose — helping to cause rolling blackouts that impacted half a million customers in the state. Drilling and transporting gas leaks methane, a greenhouse gas 80 times more powerful than carbon, nearly canceling out reduced carbon pollution from smokestacks.
As for hydrogen, experts believe it can serve a small role in a zero-carbon economy — but mostly not in the power sector. Even if it’s carbon-free when burned, hydrogen made from fossil fuels is hardly nonpolluting and also inefficient. Hydrogen fuel produced from renewables should be reserved for limited applications, they say, such as long-distance aviation fuel or to power the few gas plants still running in the middle of the century.
“In our modeling,” said Levin, “hydrogen in the power sector is used just for that last 5% of the decarbonization of the entire grid.”
Still, the power plant rules promulgated by Biden’s Environmental Protection Agency don’t wrestle with reliability, ratepayer impacts or even methane leakage. They cover carbon dioxide pollution alone, and they’re designed to reduce what’s emitted from the smokestack by 90% beginning in 2032.
That limit is based on carbon capture — in which carbon dioxide is sequestered underground rather than released into the atmosphere — a technology widely viewed as infeasible in North Carolina because of its geology. And while other techniques that would achieve the same pollution cuts are allowed under the federal rules, none are yet ripe.
One candidate is now being developed at utility scale in Texas but won’t be deployed until at least three years from now. As for hydrogen, it would have to fuel 96% of Duke’s new baseload gas plants beginning in 2032 to meet the emissions limit — an impossible feat according to the company’s own communications with regulators.
Duke’s current forecast shows its gas fleet running on about 3% hydrogen beginning in 2041, then “holding steady until significantly more hydrogen is required to meet carbon-neutral by 2050,” to comply with state law. And in a brief discussion of the impending federal power plant rules in its August draft of its long-term plan, Duke noted:
“Hydrogen is an important and potentially transformational fuel for the future of the resource portfolio, [but] the volumes necessary to utilize the hydrogen compliance pathway are not thought to be achievable on the timelines presented.”
Thus, if regulators allow Duke to build large new baseload gas plants, the company can only run them 40% of the time or less, beginning in 2032 and until technology becomes viable to slash their emissions.
The Roxboro plant, which Duke plans to put into service at the beginning of 2029, would operate at its planned capacity for just three years in that case. Afterwards, its vaunted ability to provide around-the-clock electricity would be severely curtailed.
Multiply the Roxboro conundrum by five, and the mismatch between the Biden rules and Duke’s gas ambitions becomes clear.
In its August discussion of the expected Biden rules, Duke said it considered running its new combined-cycle baseload plants at 50%. Making up for the resulting difference between demand and supply, including building another large gas plant that would run at half-speed, would require an extra $3.6 billion, the company estimated.
Tyler Norris, a former vice president at Cypress Creek Renewables and a PhD candidate at Duke University, estimates that if the 6,800 megawatts of baseload gas plants Duke announced in January were planned to run at 75% and had to ratchet down to 40% operations, the difference would be greater still. Filling it only with solar could require 9,500 megawatts of capacity in a single year — nearly double what’s online in Duke’s territory today.
“That’s probably on the high end,” said Norris, but, “it’s a pretty huge gap. Something’s going to have to change in the plan.”
Then, there’s the question of whether it makes sense for ratepayers to pay to fill that gap, especially if they’re also shelling out full price for underutilized plants.
“We’re all paying for these plants that admittedly have to sit idle more than half of the time?” asked Dave Rogers, deputy director for the Sierra Club’s Beyond Coal campaign. “Should customers really be forced to pay for those?”
Adhering to the Biden rules on coal plants appears more straightforward.
Duke must shut down its entire coal fleet by the start of 2039, and any plants still running in 2032 must be fired partially with gas. The utility already plans to meet that deadline for eight of its 12 remaining coal smokestacks, covering six sites. Two outliers in Belews Creek, just outside Winston-Salem, can already be fueled with gas. That leaves two units in Roxboro, about an hour north of Durham, that the utility now plans to keep online until 2034.
“The logical thing is to retire that coal plant at least a couple of years earlier. Whatever replaces it will be lower cost,” said Rogers. “That’s the big thing in front of the commission as it pertains to the [coal plant] rules.”
Timing also looms large. State law requires Duke to curb carbon emissions 70% by 2030, with two years’ wiggle room. If regulators authorize a nuclear or wind project that causes logistical delays beyond Duke’s control, the postponement could be indefinite. The company now hopes to exploit the latter loophole, with its preferred path to net zero achieving the 70% benchmark by 2035 or even 2037.
With their deadline of 2032, however, the Biden rules help bolster the case for Duke to rein in its carbon emissions sooner. Doing so wouldn’t just make it easier for the utility to meet the ultimate goal of near-zero emissions by midcentury. It would also significantly reduce overall carbon levels in the atmosphere.
“The thing about climate is it’s not just about achieving net zero in one year and one year only,” said Levin. “Climate is a cumulative emissions problem. If you’re doing status quo until the year you’ve made a net zero commitment, you’re not consistent with a 1.5 or 2 degree warming trajectory.”
Still, while advocates have long pressed Duke to build more battery storage, solar, and wind in place of gas and coal, making the switch in the complex utility modeling tools is no simple task, with a host of variables involved — from transmission capacity to reliability to siting.
“Duke has already submitted its modeling twice now. I doubt that either North or South Carolina commissions will want to do another round of that at this point,” said Maggie Shober, research director for the Southern Alliance for Clean Energy, on a recent webinar about the Biden rules. But, she added, “this will absolutely come up in the process before the [North Carolina Utilities] commission.”
For its part, Duke hasn’t indicated any plans to re-do its projections.
“While we are analyzing the final rules, our view is that [they do] not change our path forward in North Carolina as we continue retiring our coal plants and supporting the state’s unprecedented growth with an all-of-the-above approach that’s designed to deliver affordability and reliability for customers,” company spokesperson Bill Norton said in an email. “Natural gas remains an essential resource in this diverse mix that can be dispatched to meet demand 24/7.”
If that position holds, and state regulators don’t seek to change it, it raises the stakes considerably for the “near-term action plan” expected as part of the plan due by the end of the year, as well as the permit application pending right now for the Roxboro plant.
That short-term plan, said advocates, shouldn’t just account for the risk of new gas resources and the timing of coal retirements, but also allow for more renewables by removing the annual connection caps Duke proposes for both battery and solar.
“I think this is an excellent opportunity,” said Norris, “to revisit the potential to achieve a higher interconnection rate for zero-carbon resources.”
OIL & GAS: Louisiana is home to about a third of the nearly 200 carbon storage wells seeking permits in the U.S., but watchdog groups warn the presence of at least 186,000 abandoned oil and gas wells could complicate the process and cause safety issues. (Verite News)
ALSO: A San Antonio company files for reorganizational bankruptcy and moves to withdraw from a partnership to build a $10 billion liquefied natural gas export terminal on the Gulf Coast. (San Antonio Report)
INDUSTRY: The Biden administration is banking on “green steel” factories in Mississippi and Ohio that will run on clean hydrogen to provide a model to decarbonize one of the world’s dirtiest industries. (Canary Media)
ELECTRIC VEHICLES: Nissan delays changes at a Mississippi factory to produce more electric vehicles due to concerns about customer demand. (CNN)
SOLAR:
CLEAN ENERGY: Virginia regulators approve three Dominion Energy battery projects, and Appalachian Power issues requests for battery, wind and solar projects as the two utilities aim to meet state decarbonization mandates. (Virginia Mercury)
POLITICS: Democrats say Republican Gov. Glenn Youngkin’s refusal to rejoin a regional carbon market will cost the state $150 million annually, despite additional funding for state flood control programs. (Richmond Times-Dispatch)
PIPELINES: A pipeline safety advocate discusses concerns about the Mountain Valley Pipeline after a section ruptured during water pressure testing. (West Virginia Public Broadcasting)
CLIMATE:
COMMENTARY:
UTILITIES: U.S. gas utilities are partnering with Habitat for Humanity affiliates to build “zero-net energy homes” with gas appliances in what critics call a “cynical PR stunt” to combat efforts to curb fossil fuel use. (The Guardian)
INDUSTRY: The Biden administration is banking on “green steel” factories in Mississippi and Ohio that will run on clean hydrogen to provide a model to decarbonize one of the world’s dirtiest industries. (Canary Media)
OIL & GAS: The Department of Energy is closing a 1-million-barrel Northeast gasoline reserve established in 2014 in response to Superstorm Sandy, releasing the fuel into the market at a time when summer driving ramps up. (Reuters)
POLLUTION: A Government Accountability Office report finds natural gas peaker plants, which are more likely to be located near poor and minority communities, emit more pollution than conventional power plants. (E&E News, subscription)
CO2 CAPTURE:
ELECTRIC VEHICLES:
WIND:
CLIMATE:
EFFICIENCY: Ohio regulators last week rejected most of an energy efficiency proposal by FirstEnergy, but said in their ruling that the state’s infamous 2019 utility law doesn’t necessarily prohibit such programs. (Energy News Network)
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.
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.
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.
For all of the mobility they offer, cars, in general, spend most of their time sitting still. The average American spends around an hour a day driving, according to AAA, and in a country with roughly one vehicle per person, that’s a lot of cars just sitting around doing nothing.
Electric vehicles create an opportunity to put that downtime to use. While EVs can already serve as a backup battery for homes, engineers have long been pursuing technology to tie all of those batteries to the grid, serving as a massive virtual power plant to help manage fluctuations in electricity production and demand.
This fall, Oakland, California’s school district is making that vision a reality.
The district recently announced it is replacing all of its diesel buses with electric ones equipped with vehicle-to-grid (V2G) technology that will allow the buses to serve as a resource for utility Pacific Gas & Electric.
As Matt Simon of Wired explains, the buses provide an ideal platform. They operate on a predictable schedule, can charge during the day when solar power peaks and at night when demand is low, and are usually sitting idle during the evening, when solar generation plummets and the need for stored energy is highest.
For school districts, that also provides a new source of revenue, helping to offset the much higher cost of the buses.
So what about those millions of cars? That’s a little more complicated.
Willett Kempton, a University of Delaware professor, has been working on that problem for decades. While the concept is simple, a vast array of vehicles, charging configurations, and usage times can create a lot of uncertainty for utilities.
“When something’s pushing power onto the grid, they want to know what that is,” Kempton told Canary Media in February. “They don’t want to be like, ‘We’re 95 percent sure which car it is.’”
Kempton reached a significant breakthrough this year in developing a V2G standard that was recently adopted by SAE International, which provides guidance on universal standards for automakers on everything from tires to oil viscosity.
Major car companies are now rushing to produce models with V2G capability.
“This is a real thing,” an executive from a British V2G company told Reuters. “It’s no longer a theoretical, academic discussion.”
🚗 Speaking of electric vehicles: The Biden administration last week announced a 100% tariff on Chinese EVs, which some critics say could jeopardize climate goals; an editorial board says U.S. automakers have only themselves to blame for not being globally competitive. (E&E News, Los Angeles Times)
🔧 When getting there isn’t half the fun: As the Biden administration offers billions to ramp up hydrogen production, the fuel is dangerous and costly to transport and there are no clear rules for pipeline siting. (E&E News)
☀️ Solar’s staggering growth: The U.S. has surpassed 5 million solar installations, with more than half of those coming online since 2020, according to a new industry report. (Power Magazine)
🏭 Rust belt revival: Midwest states have received nearly $30 billion in private investments to boost clean energy manufacturing since Congress passed the Inflation Reduction Act in late 2022. (Inside Climate News)
👷 Green jobs: Community colleges around the country are offering training programs in clean energy technology, in response to a surge in job demand since the passage of federal climate legislation. (Associated Press)
🛢️ Questionable commitments: In separate reports, advocacy groups this week have called efforts to decarbonize air travel a “huge greenwashing exercise,” and said “there is no evidence that big oil and gas companies are acting seriously to be part of the energy transition.” (The Guardian)
⚖️ Energy justice: Advocates say Minnesota regulators should reinstate a moratorium on utility shutoffs after researchers found racial disparities in disconnections by Xcel Energy, even after accounting for income and other factors. (Energy News Network)
SOLAR: The first publicly available community solar project in New Hampshire hopes to pave the way for more such developments in a state where low net metering rates have made them challenging to complete. (Energy News Network)
ALSO:
NATURAL GAS: Massachusetts utility officials approve contracts between a liquefied natural gas terminal and three gas utilities that extend the facility’s life by at least six years. (Boston Globe)
COURTS: A Maryland circuit court judge dismisses complaints in a wider climate accountability lawsuit against the American Petroleum Institute but gives the city of Annapolis and Anne Arundel County 30 days to prove the trade group engaged in conspiracy. (E&E News, subscription)
GRID:
RENEWABLE ENERGY: Dozens of companies have responded to a call from the New York Power Authority to help the agency develop more renewable energy via public-private partnerships. (Times Union)
CLIMATE: Facing an unprecedented number of declared disasters since taking office, Maine’s governor plans to create a new commission to understand climate threats and mitigate potential impacts. (Portland Press Herald)
UTILITIES: New England utilities Avangrid and Central Maine Power may soon be taken private by the Spanish utility Iberdrola, which is already the utilities’ main stockholder, pending regulatory approvals. (Mainebiz)
BUILDINGS:
TRANSIT: Pittsburgh’s regional transit agency decides to permanently adopt a pilot program that automatically extended fare discounts to people receiving food assistance. (Pennsylvania Capital-Star)
ELECTRIC VEHICLES:
OIL & GAS: People who live near the Tennessee Valley Authority’s eight planned natural gas-fired power plants will likely face higher cancer rates and other health impacts from the facilities, experts say. (WPLN)
ALSO:
PIPELINES:
SOLAR:
WIND: Dominion Energy begins a new phase of construction at a Virginia facility where it will bring power onshore from its planned offshore wind farm. (WTKR)
ELECTRIC VEHICLES:
GRID: A Kentucky bill to add new hurdles for utilities to retire fossil fuel-fired power plants leads to a new high for lobbying costs as utilities and electric cooperatives spend big. (Kentucky Lantern)
RENEWABLE GAS: A North Carolina county signs a contract with a company to build a facility to produce renewable natural gas at a waste storage site. (Biomass Magazine)
NUCLEAR: A Tennessee university and community college use state grants to add programs to train workers for the nuclear power industry. (Knoxville News Sentinel)
COMMENTARY:
SOLAR: Analysts say most solar projects awaiting connection to the Western grid are hybrid installations paired with battery storage or wind facilities as California’s solar “duck curve” grows more pronounced. (Utility Dive)
ALSO:
CLEAN ENERGY: A New Mexico nonprofit launches a climate investment bank designed to finance clean energy projects benefiting low-income, disadvantaged and tribal communities. (Albuquerque Journal)
OIL & GAS:
COAL:
UTILITIES:
CRITICAL MATERIALS: Utah researchers find elevated recoverable concentrations of rare earth elements in active coal mines in Colorado and Utah. (news release)
GRID: California’s grid operator proposes raising the soft limit on power providers’ energy bids to better account for costs. (RTO Insider, subscription)
HYDROPOWER: Northwest tribal nations and federal agencies move forward on a plan aimed at restoring salmon runs decimated by hydropower dams on the Columbia River and its tributaries. (Idaho Capital Sun)
The first publicly available community solar project in New Hampshire hopes to pave the way for more such developments in a state where energy policies have made them challenging to complete.
The small southern New Hampshire town of Jaffrey is working with ReVision Energy to develop the array atop a former municipal landfill, with the goal of coming online in 2025. The town will receive annual lease payments for use of the land, and residents and others in the Eversource utility territory will be able to buy shares of the project, lowering their electricity bills and supporting the environmental benefits of renewable energy.
“It’s the perfect use of land that can’t do anything else,” said Jaffrey town manager Jon Frederick.
At the same time, planners hope the project helps demonstrate the potential for community solar in New Hampshire and spark policy changes that would make the concept more financially feasible in the future.
New Hampshire authorized the development of community solar in 2013, but only small-scale projects serving specific communities or neighborhoods have ever been built. The state’s energy policies have made larger, publicly available projects financially unworkable, even as other New England states have actively incentivized such projects by lowering logistical barriers and offering financial subsidies, said developers and clean energy advocates.
“The problem with community solar in New Hampshire is that the rate of reimbursement is much lower than the rate in all the surrounding states,” said Sam Evans-Brown, executive director of advocacy group Clean Energy New Hampshire.
At the heart of the problem are the state’s net metering rules. Net metering is a system that lets consumers offset the cost of power drawn from the grid by generating their own energy, often using solar panels. In New Hampshire, a solar system smaller than 100 kilowatts receives a credit worth 100% of the cost of transmission and the electricity itself and 25% of the cost of distribution. Systems between 100 kilowatts and 1 megawatt receive credit only for the power itself. Only municipal users can claim any credit for projects over 1 megawatt.
At the same time, community solar projects have higher administrative costs, as they need to track and reconcile the use of dozens or even hundreds of consumers. Traditionally, the net metering rates have not been high enough for community solar projects to make financial sense.
The lack of predictability is also a barrier: Electricity supply from Eversource in New Hampshire, for example, is currently priced at 8.29 cents per kilowatt-hour, down from 20 cents per kilowatt-hour over the same period last year. And the number changes every six months as the utilities update their rates.
“It is so volatile,” Evans-Brown said. “When you try to do the financial models, you’re kind of taking a bet.”
In Jaffrey, ReVision is taking advantage of evolving policies and using several strategies it hopes will overcome these obstacles.
In 2019, state legislation pushed by ReVision simplified the billing process for community solar customers. Previously, these consumers would receive a bill from the utility for their full month’s electricity use, as well as a payment from the solar operator for their share of the power generated. The new rules combined the processes, crediting the solar generation directly to a customer’s electricity bill. That streamlining was just enough to get things moving in Jaffrey, said Dan Weeks, ReVision’s vice president of business development.
“That was a big barrier in the past,” he said. “With that administrative progress we felt we were far enough to take this big step.”
The project deals with the size limit on net metered projects by keeping its AC capacity just below the 1 megawatt mark, so it remains eligible.
The company decided to sell shares in the development rather than opening it up to subscribers, a choice that creates more value for consumers, who get to own all the power produced and the associated tax credits. The idea is that consumers will receive low- or no-cost power even as retail electricity power prices increase, creating savings that will pay for the initial investment, and then some.
Historically, however, it was difficult to make those numbers pencil out because of the combination of low net metering rates and frequently changing power prices. Indeed, the current supply price of 8.29 cents per kilowatt-hour would not be enough to keep the project afloat. ReVision is banking on U.S. Energy Information Administration projections that power prices will go up in coming years, creating greater savings for shareholders.
“There will definitely be a different rate at the time it is turned on,” Weeks said. “We feel pretty confident that individuals will save regardless.”
An ongoing difficulty remains, however: State law requires the total consumption of the community solar group members be equal to or greater than production of the solar farm. However, many shareholders are interested in buying a stake that is larger than their consumption so the solar credits will offset their entire energy bill — the delivery of the power as well as the electricity itself. That leaves ReVision with an unbalanced equation.
This dilemma is likely an unintended side effect of the way net metering rules have evolved in the state, Weeks said. ReVision is in talks with legislators about how they might be able to change the law to remove this obstacle, a move that would benefit both the Jaffrey project and future community solar plans.
“We have willing legislators who want to address it, so the program can realize its intended goal,” Weeks said.
If a change in law does not come through, ReVision will look into partnering with nonprofit groups or municipalities that might be interested in buying smaller amounts of power to offset some, but not all, of their consumption, which would help rebalance the legally required equation.
As the plan comes together, others in the New England solar space will be watching, Evans-Brown said.
“The thing that’s exciting about ReVision doing this is it’s kind of a trial to see if we can make this work,” he said.
.svg)
