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The company seeking to build one of the nation’s largest carbon sequestration projects in Indiana was trying to avoid a “PR disaster” by locating in a rural farming area, a company executive said at a community meeting recently.
But that decision has not preempted controversy over both the project itself and the company’s larger strategy.
Local opposition is quickly snowballing in the small towns around Terre Haute as the EPA considers whether to approve injection well permits crucial for a federal loan guarantee.
Wabash Valley Resources says it wants to build a fertilizer plant that will bring jobs to rural Indiana. It aims to use petroleum coke or other feedstocks to create hydrogen and then anhydrous ammonia while sequestering carbon dioxide emissions 4,500 feet below ground in Vigo and Vermilion counties, about 12 miles from the plant.
Residents feel the company and the federal government are making them “guinea pigs,” as several said, in a project aimed at taking advantage of lucrative federal grants and tax incentives.
The company has been seeking to capture and sequester carbon since 2016, when it bought the former Duke Energy coal gasification plant that it plans to retrofit.
The EPA on July 7 issued a draft permit for the two Class VI carbon injection wells. Residents said they were given only days notice by mail about the lone EPA public meeting on the issue, which was held August 10.
Many local farmers had never heard about the concept, and were outraged that the company did little outreach and the government gave them little notice about their chance to weigh in. A 35-day public comment period on the draft permit — shorter than typical 60-day periods — was scheduled to close Aug. 11. The deadline was extended to Aug. 21 at advocates’ behest.
“We understand that once landowners learned it was going in their backyard, there was a short ramp to learn about carbon storage,” Wabash Valley spokesperson Greg Zoeller said. “Admittedly, we could have done better initial outreach to the landowners. We hoped the EPA information session would ease most of their concerns.”
Since that was clearly not the case, the company held its own meeting Aug. 16 in the small town of Universal, where residents pelted the officials with questions and accusations.
Wabash Valley Vice President of Operations Rory Chambers was asked why the carbon couldn’t be sequestered at the gasification plant site.
He responded that injecting carbon there — under a river and closer to Terre Haute — would be a “PR disaster.”
“Admittedly a little self-servedly I said, ‘Well if I put it in my plant site, this plume will clip the north side of Terre Haute and I end up with 3,000 angry people,” Chambers said.
By sequestering the carbon around Universal, “If there are a few mad people, here I can talk to individuals…and calm them down,” Chambers said. “My god, if there’s 3,000, I’ll never be able to convince them.”
As outrage erupted in the room, Chambers continued:
“It’s not because you’re rubes, I don’t think you’re rubes,” he said, adding that he himself does not have a college education.
Wabash Valley founder Nalin Gupta, meanwhile, explained to the crowd that he previously worked in finance in New York, on a team deploying over $85 billion in energy finance.
“If someone said, ‘Here, take two billion dollars and do something that would destroy people’s properties and water,’ would I do it?” Gupta asked the crowd in an ill-fated attempt to reassure them about the company’s motivations.
“Yes!” someone yelled out. “Nobody in this room wants it!”
Susan Strole-Kos told Chambers at the meeting that she has spent many hours looking at data and studies about carbon sequestration, and fears the underground carbon plume could harm the farm that’s been in her family for 200 years.
“I have been given the job to be the steward of my land, and you are trying to take that from me,” she said tearfully. “It may be legal because you have worked politicians, you have the law in your favor, but it is immoral, and I don’t know how you guys can live with that.”
Strole-Kos said her family was approached by the company last year and invited to what they described as a meeting of local farmers about a fertilizer plant.
She thought it could be a good idea. But when she arrived, she found no other residents, just Chambers and two other company representatives who pressured her to “sign a piece of paper” in exchange for a few hundred dollars, as she told Energy News Network.
“I said, ‘No we are not fools here,’ it did not end well,” she said. “Maybe they thought we were just simpletons out in this area.”
Hundreds of residents turned out for a second meeting with company officials on Aug. 22, at an elementary school near the injection well site. Strole-Kos’s daughter Whitney Boyce, a high school teacher, worries about danger to students.
“We have our natural disaster drills, tornado drills, earthquake drills, we recently added active shooter training; now how do we prepare for a carbon dioxide leak?” she said. “We have to notify students and parents when people come in to spray for bugs. So I find it mindboggling we don’t have to notify parents when something like this is coming in.”
The federal Inflation Reduction Act expanded the 45Q tax credit to $85 per ton of sequestered carbon dioxide. Provisions of the Bipartisan Infrastructure Law could also aid Wabash Valley’s plans.
The U.S. Department of Energy meanwhile is funding the development of hydrogen as a clean fuel, and there are various tax credits available for hydrogen production that the company could potentially tap. Wabash Valley Resources currently has a $33 million federal grant for hydrogen technology demonstration.
During the Aug. 16 meeting, Gupta touted the federal government’s support.
“The Trump administration reached out to me and said restart this plant, we don’t want ammonia from Ukraine and China,” Gupta said. “$20 million was given to us in 2019 by the Trump administration, it was followed by [support from] the Biden administration.”
Zoeller told Energy News Network that “this is not a local project, this is really the first of what I see as a change away from smokestack industry.”
But as multiple carbon dioxide pipelines and sequestration sites have been proposed in the Midwest, residents have raised fears of safety, environmental and economic consequences should carbon escape, as it did in a 2020 disaster in Sartartia, Mississippi. In Illinois, for example, residents and local governments are stridently opposed to the company Navigator’s plans for a carbon dioxide pipeline and sequestration of emissions from ethanol plants.
Near Terre Haute, residents are especially concerned since the area is a seismically active zone, and there is an abandoned coal mine underground.
During the contentious Aug. 16 meeting, Gupta repeatedly noted that there are 145,000 active and defunct carbon injection sites nationwide — mostly in Texas and California. Such sites have long been used for enhanced oil recovery, where carbon is injected into the ground to force hard-to-extract oil out of diminishing reservoirs.
Though common, critics consider enhanced oil recovery to be under-regulated and under-studied, posing a potential risk to drinking water. And they fear large-scale, permanent sequestration of carbon dioxide raises different and little-understood issues.
Doug Martin is town board president of Universal and lives less than two miles from the proposed injection site. He says the company never reached out to the town nor the local fire department.
“How can you say you have an emergency plan when Universal has never been contacted?” said Martin, an author and former creative writing professor at Indiana State University.
“I don’t want to walk out and see people passed out in their yards with permanent brain damage. It’s right by our park too, where kids play. My guess is when they start shooting that much into the ground, it’s going to go under all the houses.”
Under state law, Wabash Valley does not need permission from landowners to sequester carbon below their land. A state law passed last year mandates that permission is needed from 70% of landowners, but that law specifically exempts the “pilot project” developed by Wabash Valley.
In April, the legislature passed a law setting the price the company will pay surface landowners if carbon migrates below their land. Indiana state legislators have sought to pass a law insulating Wabash Valley Resources from liability, unless landowners can prove actual harm from carbon dioxide migration.
Meanwhile a 2019 state law declared carbon sequestration in the public good and allowed the use of eminent domain for siting the pipeline from the plant. During the community meeting, Wabash Valley officials said they would use eminent domain as a last resort, if they cannot obtain permission from landowners on the pipeline route.
Wabash Valley has said the plant will open in 2026, but Kerwin Olson, the executive director of environmental group Citizens Action Coalition, predicted the process will take much longer, as the company still needs “a jigsaw puzzle” of various federal and state permits to construct the pipeline and open the plant.
He said that in the meantime, the public is bearing unfair financial risks, in the form of federal grants and subsidized loans, not to mention tax credits and potential damage down the road.
“To me what this is really all about at the moment is them getting their money, where the public is assuming all the risks on the financial side of things,” Olson said.
“It’s potentially a Solyndra 2.0,” he continued, referring to the solar company that failed after receiving high-profile federal subsidies under the Obama administration.
In comments filed with the EPA, the Citizens Action Coalition argued that producing and transporting the petcoke, coal, corn stover or biomass feedstock for Wabash Valley’s plant would create more carbon emissions than they plan to sequester.
The coalition proposed in its EPA comments that a fertilizer plant could more efficiently and cleanly operate using the electrolysis method powered by renewable energy, rather than “the Rube Goldberg-machine approach replete with multiple sources of various toxic air emissions, acid gas generation, slag, carbon emissions, and risks to private property and public health.”
Citizens Action Coalition organizer Bryce Gustafson said it appears the increasing number of concerned local residents are “in it for the long haul.”
“They haven’t lost hope,” he said. “A lot of people were under the impression EPA was going to rubber stamp this, but now they’re understanding there are ways they can keep the fight going. When people come together and stand up for their rights, for their communities, it makes me proud to be a Hoosier.”
Reprinted from E&E News with permission from POLITICO, LLC. Copyright 2023. E&E News provides essential news for energy and environment professionals.
For years, Delaware has been on the sidelines as the emerging offshore wind industry flocked to neighboring states, but a new law could transform the industry in the state — if it’s not too late.
Delaware’s Democratic-led Legislature recently ordered a study of the state’s offshore wind potential to be reported back by the end of the year. The move, which was signed by Gov. John Carney (D) this month, adds momentum for the state to set its first target for offshore wind, a goal of many lawmakers and environmental groups.
“We’re alone among our neighbors of not really having wind targets,” said state Sen. Stephanie Hansen (D), who has spearheaded the state’s reassessments of offshore wind to meet its climate targets as chair of the state Senate Environment and Energy Committee. “Delaware, as of now, I think, is really firing on all cylinders to move into the next phase of energy planning and implementation.”
If the study leads to a state offshore wind goal, it would bring Delaware in line with neighboring states and give it an opportunity to compete for industry jobs and businesses emerging along the East Coast. Power grid operator PJM Interconnection LLC is assisting with the study in looking at transmission impacts. But concerns about the cost of offshore wind still linger from a 2018 analysis that effectively tabled wind ambitions in the state for years.
Meanwhile, a movement against offshore wind along coastal communities has begun to capture the sentiment of Delaware towns and some lawmakers.
“I think it is harmful,” said state Sen. Bryant Richardson (R), the only senator to vote against Hansen’s study. He opposes the offshore wind industry due to its potential costs and what he says are negative impacts to the ocean environment and views from the shore.
“It’s an eyesore,” he said of the industry.
Delaware is juggling its offshore wind future as the industry reaches a turning point in the U.S.
Thousands of turbines are expected to go up in the northeast Atlantic in the coming years, spurred by state commitments and subsidies from Maine to Virginia. That comes alongside millions of dollars of promised state and private investments to beef up aging ports, build manufacturing and steel fabrication facilities, and make job programs to create a workforce capable of building and maintaining the new industry.
The wave of new proposals is partly thanks to the Biden administration’s commitment to raise enough wind farms in the ocean to power 10 million homes by 2030. The White House on Tuesday approved the nation’s fourth commercial-scale offshore wind farm off the coast of Rhode Island and has said it remains “on track” to reach 16 offshore wind environmental reviews by 2025.
The administration also announced last month potential new lease areas in the central Atlantic, including a swath of ocean about 30 miles off the coast of Delaware Bay. If developed, that area would add to two planned offshore wind farms that sit off the Delaware coast in federal waters.
Delaware’s grid may not reap the power of those two offshore wind projects, which are helping Maryland meet its offshore wind target. But experts say the new offshore wind areas could offer electricity to help Delaware reach its renewable portfolio standard of 40 percent renewable power by 2035.
Chelsea Jean-Michel, a wind analyst at BloombergNEF, said local opposition and limited space has made it difficult for the state to grow its renewable sector onshore, making offshore more attractive.
“Offshore wind projects can help decarbonize Delaware’s energy system by providing bulk renewable energy capacity in one go,” she said in an email.
For years, Delaware has flirted with the idea of offshore wind to help it decarbonize. It was poised to be the first U.S. state with an offshore wind farm when the proposed Bluewater Wind offshore wind project secured a long-term contract more than a decade ago with the state’s utility. The proposal later fell apart, largely because of cost concerns and investment uncertainty amid the recession.
Offshore wind got a second look largely thanks to Carney, who in 2017 ordered a study of the industry’s potential role in reaching state clean energy goals.
That analysis found that the cost of offshore wind energy would be high, prompting many lawmakers to shy away from supporting turbines off the coast.
One reason why offshore wind is getting another look in the state now is that costs have fallen significantly as projects have advanced in the U.S.
An updated report from Delaware’s Special Initiative on Offshore Wind (SIOW) last year found the cost of a Delaware offshore wind project — if it was large enough to capture economies of scale — would cost the same as existing sources of electricity in the state like natural gas and solar. That would be the case without state subsidies or tax breaks, researchers said. The study considered federal incentives that were expanded in the Inflation Reduction Act giving developers a 30 percent tax credit for offshore wind.
“There’s enough time, plenty enough time, for Delaware to do one project, maybe two, and still get advantage of that tax credit,” said Willett Kempton, a professor at the University of Delaware’s School of Marine Science and Policy and a leader of SIOW.
Kempton’s report also weighed how fossil fuels negatively impact human health and the environment, driving up the overall cost of using those sources for power. When those factors were considered, offshore wind became cheaper than existing sources like natural gas in the study’s models.
Hansen said Delaware hired analysts to interpret the report. When executive action did not occur, she said she wrote the legislation that passed earlier this year tasking the governor’s office and state regulators to review and report back to the Legislature on offshore wind’s potential.
“We need to hear from the administration on this, is this a direction that we ought to go?” she said. “I can tell you that there is the legislative will to move this forward. But we also aren’t experts.”
Carney’s office declined to comment for this story.
Hansen said that Delaware’s tardiness on offshore wind could lead it to lose out on benefits from the industry, such as jobs and manufacturing.
Jean-Michel, with BloombergNEF, noted wind developers have forged relationships with nearby state lawmakers that give those states an advantage.
“Given that it’s entering the market later and it is likely to be a smaller market, Delaware may not benefit as much economically through offshore wind in terms of green growth or jobs, or it may have to pay a significant premium for offshore wind projects if it wants to stimulate that local manufacturing sector,” she said.
However, Kempton, with the University of Delaware, said he would warn lawmakers, if they proceed with a procurement target in Delaware, against tying offshore wind projects to local investment.
Other states have encouraged offshore wind developers to bundle economic development plans into their wind proposals, leading to manufacturing projects planned in states like New York and Maryland.
But those investments mean the price of electricity for those projects is higher, Kempton said, noting that wind developers may not be the most effective planners for associated supply-chain businesses. They also may not have long-term commitments for jobs in mind onshore.
Offshore wind supporters are hoping when the Delaware Legislature meets again in January, lawmakers will have offshore wind on their minds.
Hansen said she couldn’t disclose some of the conversations happening now on offshore wind but that Delaware leaders could make progress even before the session convenes.
But as the state weighs a greater role for offshore wind, industry opponents may also be growing.
It’s a pattern that has played out in other coastal states as offshore wind proposals draw pushback from beachfront homeowners who don’t want steel marring their ocean views and town councils concerned the industry could hurt tourism. Conservative groups such as the Delaware-based Caesar Rodney Institute also are supporting the opposition movement.
Richardson, the Delaware Republican, said he’s been reading material put out by the institute on offshore wind and connecting with opponents who share his skepticism about the industry, its costs and its impacts.
“I hope it will fail,” he said of the state’s plan on offshore wind.
Critics say a pair of proposals to make Appalachian Ohio part of regional hydrogen hubs is likely to benefit the state’s oil and gas industry more than the climate.
The two proposals are among 21 projects competing for shares of a $7 billion pot of grant money under the 2021 Bipartisan Infrastructure Law. The law defines hydrogen hubs as networks of clean hydrogen producers, their potential consumers and infrastructure connecting them. At least one of the winning projects is to be a “blue” hydrogen hub, meaning it would make hydrogen from fossil fuels with carbon capture, storage and possible reuse, or CCUS.
The Appalachian Regional Clean Hydrogen Hub plans to collect methane from a web of natural gas pipelines in Ohio, West Virginia, Pennsylvania and Kentucky for a hydrogen production facility in West Virginia. The ARCH2 coalition includes Battelle, natural gas industry companies, the state of West Virginia, and more.
The Decarbonization Network of Appalachia, or DNA H2Hub, has the economic development group Team Pennsylvania as its project lead and is also proposing a blue hydrogen hub for Pennsylvania, West Virginia and Ohio. Equinor and Shell are among the group’s corporate partners.
Because both hubs would use methane from the region as feedstocks, they represent potentially large customers for the natural gas industry.
“We believe there are opportunities for the industry in a regional hub or hydrogen ecosystem and that Appalachia is more suited than most areas because of our compactness, access to natural gas and manufacturing infrastructure,” said Rob Brundrett, president of the Ohio Oil & Gas Association. “There certainly would be a benefit, especially the role natural gas plays in the creation of blue hydrogen, but we think it is too early to tell exactly what and how much benefit it may be to the industry.”
Much will depend on how hydrogen from the hubs will be used, whether it will displace other current uses of methane, and overall costs and market prices for natural gas. Rough estimates from the Ohio Oil & Gas Association are that recent production has gone in equal shares to power generation, heat and chemicals.
On the high end, blue hydrogen hubs might increase natural gas consumption and industry revenues. On the low end, sales to hydrogen hubs could offset potential losses if other uses decrease as a result of the energy transition.
Hydrogen production with natural gas and capture of carbon emissions from burning natural gas have gone on for decades, said policy advisor Rachel Fox at the American Petroleum Institute. Current U.S. hydrogen production is approximately 10 million metric tons per year, she said.
“The new challenge and opportunity is to scale these two complementary technologies together,” Fox continued. “API and our members are excited about the H2Hubs program and the impact it could have on the growth of a low-carbon hydrogen economy.” She said the industry has shown 65% to 90% carbon capture rates are commercially achievable.
As a decarbonization strategy, a blue hydrogen hub would be “a really energy-intensive, really water-intensive thing that commits that sector to being fossil-based forever, essentially,” said Emily Grubert, an energy policy expert at the University of Notre Dame.
It’s unclear whether blue hydrogen “would even result in a net reduction of carbon emissions,” said Ben Hunkler, communications manager for the Ohio River Valley Institute. In a 2022 analysis, he said a blue hydrogen hub would be “a risky gamble,” whose costs likely outweigh environmental benefits when compared with other options, such as renewable energy.
Although industry and government “now talk about carbon capture as having been proven, it really hasn’t,” said David Schlissel, director of resource planning and analysis for the Institute for Energy Economics and Financial Analysis. There hasn’t been any long-term, large-scale demonstration of its effectiveness over the time frame when promoters expect blue hydrogen hubs to operate.
Methane leakage from pipes and other infrastructure would add to emissions, Schlissel said. Methane is a more potent greenhouse gas than carbon dioxide, and numerous studies have found methane emissions are vastly underreported.
Hydrogen can also leak, especially because its molecules are so small. “We think it leaks everywhere, but there’s no commercially available technology that can measure hydrogen leakage,” Schlissel said. Leaked hydrogen could prolong methane’s impacts in the atmosphere, researchers reported in Nature Communications last December.
Notably, both the Ohio Oil & Gas Association and the American Petroleum Institute have commented against the U.S. Environmental Protection Agency’s proposed rules that would effectively require carbon capture and storage for fossil fuel-fired power plants.
The ability to outfit power plants with carbon capture equipment isn’t advanced enough to be feasible yet, Brundrett said. “Therefore, at this time we would not encourage any mandates regarding a technology that isn’t available to the scale required by the rules.”
It’s unclear how the CCUS technology for a power plant would differ from that for a hydrogen production facility. Brundrett said the technology “has a promising future, and we will remain engaged in the hydrogen hub process with the hope that Appalachia is able to utilize our natural advantages if awarded by the federal government.”
For now, chances seem good that at least one of the projects will get funding. The Bipartisan Infrastructure Act requires at least two regional clean hydrogen hubs to be in places with “the greatest natural gas resources.” Separate provisions let the Appalachian Regional Commission provide grants and technical assistance for a regional hydrogen hub.
The federal funding is meant to act like a “moon shot,” to quickly ramp up clean hydrogen production.
“The reality is that we believe that there’s a near-term climate need that we need to be addressing, [and] that we need to think about how quick can we bring one of these technologies or a lot of these technologies to the marketplace,” said Thomas Murphy, senior managing director for strategic energy initiatives at Team Pennsylvania, during a webinar presented this summer by Appalachian Energy Future, an industry-led alliance promoting hydrogen hubs.
The DOE initiative aims to “[drive] down the cost of getting new technologies into the market,” said Grant Goodrich, who heads the Great Lakes Energy Institute at Case Western Reserve University. “You’re increasing market readiness and market demand.”
And while scaled commercial carbon capture and storage technologies don’t yet exist and can’t operate without government support, the Department of Energy’s hydrogen hub initiative could jumpstart a hydrogen economy for hard-to-electrify uses, such as high-heat industrial processes, heavy-duty transportation, or aviation, Goodrich said. That in turn might lead to effective carbon capture for other hard-to-decarbonize industries that produce greenhouse gases, such as the cement industry.
The DOE guidelines also call for projects to track how clean their processes turn out to be, Goodrich said. That should provide some accountability.
DOE’s decisions on the grant applications could come before the end of the year. DOE will also spend $1 billion to develop demand for hydrogen from the hubs, the agency announced in July.
One by one, tiny solar companies abandoned their rooftop ambitions in Prince William, defeated by tangles of red tape in the booming Northern Virginia county.
Undeterred, Ray Masavage, owner of CAVU Solar since 2018, hung in there. Why?
It pained him to see seas of array-less houses in sprawling subdivisions as the planet cooked. And he had faith that officials in the county he calls home yearned to shed the label of worst solar permitting jurisdiction in the state.
Now, he’s hopeful that a Board of Supervisors vote to waive fees associated with new residential solar installations beginning Sept. 1 represents a crack in county bureaucracy. It’s just one piece of a long checklist of potential improvements to streamline solar permitting.
“In terms of diplomacy, this is a big deal,” Masavage said. “I give county officials credit for looking at the problems and doing something about them.”
He also praised Solar United Neighbors, an advocacy organization with roots in Virginia, and the Chesapeake Solar & Storage Association, a Mid-Atlantic trade group, for pressuring the county to simplify long-lingering, tedious permitting requirements and boost transparency.
“We’re contractors working 24/7,” Masavage said. “We can’t stop when we’re on a roof somewhere and go back to address a resubmission in Prince William County.”
The county’s balky application website, higher-than-average permitting fees, and nitpicky reviews requiring multiple plan submissions had paralyzed many solar companies and bedeviled homeowners puzzled by the lack of forward movement on planned arrays.
Last December, mounting discontent prompted Solar United Neighbors to invite frazzled homeowners in Prince William to participate in an Action Alert. SUN wanted residents to know that the county — not installers — was to blame for delays and setbacks.
That alert encouraged residents to send complaint letters to both their local county board supervisors and the editors of local newspapers.
Prince William authorities took note.
In February, the county named Mandi Spina as acting director of the Department of Development Services. She replaced — at least temporarily — Wade Hugh, a county employee for 27 years.
In her new role, longtime county employee Spina said she had multiple phone calls with Aaron Sutch of Solar United Neighbors and wanted “to thank him for his continued advocacy of the solar community as well.”
Spina also lauded what’s called the Residential Solar Working Group, which Hugh had rolled out last November. Its 14 members included county staffers and industry representatives intent on repairing the fumbles of the past.
She noted that the impasse began to break when more than 55 stakeholders met on July 12 to hash out their differences.
“This is important as we are committed to partner with industry,” she said.
Sutch, director of SUN’s Atlantic Southeast Region, said he’s encouraged that the campaign has yielded results.
“This feels good and we applaud the county’s decision,” he said. “It’s the first measurable step. But it still has to be followed up with other major improvements.
“Solar is not going away. People in the county want it.”
In late July, supervisors allocated $1.2 million from the county’s year-end savings to a one-time fee reduction on new solar installations through June 2024.
Earlier this month, Spina was named deputy director of the Department of Development Services. That followed an earlier personnel shift, when Hugh was promoted and appointed deputy county executive for community development in late June. He now oversees numerous county agencies, including development services, which he used to lead.
The development agency will initiate a budget request for the next fiscal year to extend the waiver beyond the June 2024 deadline, possibly making it permanent, Spina said.
“I understand we are an outlier compared to our neighboring jurisdictions,” she said about the urgency of reducing permit costs and speeding up timelines.
Indeed, by digging into a federal Solar Trace database, Solar United Neighbors researchers confirmed that Prince William’s median solar permitting fee of $586 was more than double that of four surrounding counties, where fees ranged from zero to $200.
As well, between 2018 and 2021, solar permitting took longer in Prince William than it did in Arlington, Fairfax, Stafford and Loudoun counties.
While waiving the permit fee attracted across-the-board kudos, solar contractors and advocates are encouraged by a handful of other actions to be initiated by the county because of the due diligence of the working group.
For instance, Prince William is issuing a standard list of pre-approved solar components, which will save the industry from having to submit safety compliance listings with each application.
In addition, the county and industry representatives are jointly designing what’s called a residential solar county typical plan. This will eliminate the need for engineers to sign and seal documents because all pertinent information is already included. Instead of dragging on, review time is limited to five business days.
The county is also on track to adopt a pilot program for Solar APP+, a tool developed by the National Renewable Energy Laboratory to standardize the rooftop permitting process.
Solar APP+ is deployed widely in California and Arizona. In Virginia, Prince William would join Richmond, Culpeper County and Harrisonburg, three other jurisdictions testing it on trial runs.
Warming to the online application would be fantastic for smaller operators, advocates say. The conversion would allow all players to be on the same page because the software integrates with existing government regulations, automates plan reviews and provides final signoff of inspections.
“I am confident that” these upgrades “will provide a wide range of options to alleviate frustration surrounding the time and cost to permit in Prince William County,” Spina said.
Sutch said the county of 484,000 residents could be a solar haven if updated policies fulfill the promise of matching contractors and homeowners.
“We feel we’re 40% to 50% of the way there,” he said about busting up the logjam. “This is proof that if you are persistent enough and know the levers of power, you can make a difference. Now, we want to hear positive stuff.”
“We’ve seen tremendous growth with solar projects,” Spina said. “And we know that growth is going to continue.”
Successful applications for installations, which stood at just 14 in 2016 and 19 in 2017, leaped to triple digits — 149 — by 2018. Except for a setback caused by the pandemic, they have ramped up at a steady clip.
By 2022, applications for solar projects had exploded to 1,087 — roughly quadrupling the 2021 total of 274. Each one required both an electrical and a structural permit.
Hugh stood by the rooftop solar data he compiled, although advocates questioned the validity of his records. They constantly questioned why it took so long to greenlight projects — which often didn’t happen until a developer made a second try. Each repeat submission added roughly $100 to the permit cost.
Ideally, developers desire approval within a month for the sake of efficiency and to keep installation costs close to the estimate provided to homeowners. They had to walk away when waits were interminable, thus rendering projects cost-prohibitive.
Masavage is a licensed pilot whose company, CAVU, is shorthand for the aviation term “clear and visibility unlimited.” Prince William’s efforts to expedite permitting are encouraging him to double down.
“To have all of these homes that are perfect candidates for solar is an amazing dream,” he said. “We’re facing a world crisis and, as installers, we have the ability to do something about it.”
Spina is optimistic that the changes will lure solar contractors to the county — and allow the local government to meet its strategic goals of sustainable energy consumption.
Still, some installers remain content to keep their distance.
Nolie Diakoulas, who heads up 10-year-old Virginia Beach-based Convert Solar, expanded his small business’ reach statewide three-plus years ago as interest in renewable energy swelled.
However, he began second-guessing his forays into Prince William when the hurdles proved constant and insurmountable.
Diakoulas backpedaled when basic fees connected to permitting escalated beyond $1,000, too big for an installation to be profitable. He figured the county was a better fit for Ion, Tesla and other solar giants with access to a cadre of internal system designers, engineers and other specialists.
The recent county turnaround isn’t even on his radar.
“We have stopped installing in Prince William County,” he said, “so I have not been keeping up with the news.”
Correction: Buildings account for about 40% of Minnesota’s total energy consumption. An earlier version of this story misattributed the figure to heating only.
Michael Overend and Lucy Grina love to show visitors around their home, a modest four-bedroom rambler, built in 1965 on a gravel road just north of Duluth, Minnesota.
The couple’s pride, however, did not always extend to one feature: the utility bills.
“We were embarrassed about how much heat this old house was leaking,” Overend said, “and we were cold a lot.”
Today, the couple is among a small but growing number of northern Minnesota homeowners finding comfort and savings by pairing energy-saving weatherization with an all-electric heating and cooling system known as a heat pump.
Heat pumps are highly efficient, two-in-one appliances that can both heat and cool a home, even in a notoriously cold climate such as northern Minnesota. The technology will likely be a key component of the state’s climate strategy, as buildings are a significant contributor to the state’s greenhouse gas emissions.
While still a niche, utilities, contractors, and advocates expect the technology to take off as more incentives become available and more people become familiar with what it can do.
For Overend and Grina, it started with consulting an expert on building super-efficient homes. They had raised two children in their home, but as they retired they had to decide whether to keep the house and improve its livability or buy elsewhere.
The first step was to get an energy audit, and then contractors plugged holes and added insulation and efficient windows. Eventually, the home was so tight they had to install an air exchanger to keep the air fresh and healthy. That’s standard practice in energy-efficient home construction these days.
Next came the heat pump. The systems have been around for decades, but their performance and efficiency improved by leaps and bounds in recent years. Those improvements, along with growing awareness about climate change and the hazards of burning fossil fuels indoors, have helped raise the appliance’s profile in recent years.
Heat pumps are more efficient than furnaces because they don’t make heat; they move it from one place to another, the same as refrigerators do. The outdoor unit looks essentially like a standard air conditioner. It has a coil filled with refrigerant and a fan that blows air across the coil. The indoor unit also has a coil and a fan. As the refrigerant moves through the system, a compressor pressurizes it and then allows it to expand, causing it to shift between a gas and a liquid. This enables it to absorb heat outdoors and release it inside.
In the summer, the system can be reversed, removing heat from inside more efficiently than a standard air conditioner can.
The most advanced heat pumps can extract heat from the air even on very cold days. This is because of newer, variable-speed, inverter-driven compressors. They are more efficient because they run continuously at varying speeds to match the heating or cooling load in the house, rather than stopping and starting as most furnaces do.
Overend said his system keeps the house toasty down to 20 degrees below zero Fahrenheit. There are backup electric radiators, and the system can switch automatically to the backups, but Overend said they hardly ever come on.
Overend said the new system — including removing the old furnace, installing the two heat pumps and some new ductwork, and adding the air exchanger and a new water heater — cost the couple about $25,000, and it has lowered the home’s energy use by 40%.
Savings depend on the type of system the heat pump is replacing. Homeowners who rely on propane can save as much as 30% on home heating costs; those using electric resistance (baseboard) heat can save as much as 50%, according to the Air Source Heat Pump Collaborative, a project of the Minneapolis-based nonprofit Center for Energy and Environment and major utilities in the state.
The collaborative’s manager, Rabi Vandergon, said rebate applications for heat pumps spiked in 2020 during the COVID-19 pandemic, as more people focused on home improvement. Supply chain problems slowed sales some, but numbers are up again this year, he said.
“We expect to see another jump,” Vandergon said. “People want to help with climate change, especially if it doesn’t hurt their pockets.”
Vandergon said the new systems are most valuable for rural residents currently served by propane or electric baseboard heating. The financial case is less clear to natural gas customers, but he’s excited about the rebate and tax credit programs soon to be available through the federal Inflation Reduction Act and Minnesota’s landmark 2023 energy legislation.
Homeowners can save more when they combine heat pumps with dual-fuel programs offered by some utilities. Minnesota Power, for example, offers customers a lower rate in exchange for the ability to stop the heat pump during times of high energy demand, forcing the home to switch to backup heat from another source.
Limited research and the increasing confidence of experienced installers are persuading homeowners that heat pumps really can work in cold climates.
HVAC contractor Chad Thompson has been installing heat pumps since he started Twin Ports Custom Climate just across the border in Superior, Wisconsin, 20 years ago. He’s witnessed monumental improvements in technologies and equally encouraging changes in consumer attitudes.
“The capabilities of the new units have gotten probably 10 times better over the last 10 to 15 years,” Thompson said.
Sales growth has occurred mainly by word of mouth. Things took off during the pandemic, Thompson said, while the region’s increasingly hot and humid summers have probably prompted interest, too. Others are motivated by climate change and the desire to stop burning fossil fuels.
The number of applications for utility company rebates for heat pumps in Minnesota more than doubled over four years, from just over 2,000 in 2019 to 4,600 in 2022, according to the Air Source Heat Pump Collaborative. And sales of heat pumps in the U.S. surpassed sales of natural gas furnaces in 2021, according to the International Energy Agency.
In the northeastern part of the state, Minnesota Power is bullish on heat pumps, offering rebates for the last several years. The company holds annual training events for contractors to learn from experts and manufacturers, and it requires customers to use preferred contractors to get a rebate.
“We want to encourage customers installing electric heat to do something that’s high efficiency, something that’s beneficial to the grid,” said Minnesota Power’s Jon Sullivan, lead worker in customer programs and services. “This technology really helps us along the path to 100% carbon-free energy. It’s also beneficial for other customers who want to cut back fuel combustion as much as possible.”
In 2017, Minnesota’s buildings consumed 40.6% of the total energy used in the state, according to the Minnesota Department of Commerce. Most of that comes from homes, where heating and cooling use more than half of the energy consumed. In spite of efforts to boost efficiency, energy use in buildings is increasing in Minnesota.
Advocates say switching to electric cars and appliances is among the most impactful things a homeowner can do to combat climate change. That’s because electricity is increasingly generated from clean sources. In Minnesota, all electricity sold will be required to come from clean energy by 2040.
As for Overend and Grina, they’re thinking about possible next steps, including an electric vehicle and possibly battery storage to tap during power outages.
“Ten years ago, I had no hope,” Overend said. “I thought climate change was too big for anyone — or for all of us — to solve. I’ve learned that there truly is hope. What we do as individuals makes a very, very tiny contribution to the overall picture. But we can be an important example to our friends, our family, our community.”
The following commentary was written by Laura Sherman. Sherman is president of the Michigan Energy Innovation Business Council, a trade organization of more than 140 advanced energy companies focused on improving the policy landscape for the advanced energy industry in Michigan. See our commentary guidelines for more information.
Michigan can grow its economy and add more well-paying jobs by realizing the clean energy goals set by Gov. Gretchen Whitmer with the adoption of state-level policies, according to a new analysis.
The report from 5 Lakes Energy and the Michigan Energy Innovation Business Council (Michigan EIBC), The Michigan Clean Energy Framework: Assessing the Economic and Health Benefits of Policies to Achieve Michigan’s Climate Goals, finds that clean energy and a strong economy go hand-in-hand. Using economic modeling tools developed by RMI, the report concludes that the Michigan Clean Energy Framework, a set of state-level policies to cut emissions, would lead to the creation of about 160,000 more jobs and over 2.5% higher state GDP growth by 2050.
Clean energy is an increasingly important part of Michigan’s economy. Gov. Whitmer declared that Michigan would be a part of the transition toward low-carbon energy when she set the goals and released the MI Healthy Climate Plan.
But still, more must be done to achieve those goals. Various pieces of legislation have been introduced in Lansing that would support the clean energy industry and cut emissions across the state’s economy. The policies modeled in the report include:
Instituting these policies will stimulate economic development and job growth that would otherwise not occur. The time is especially ripe for this type of economic development because of federal funding for emissions reductions offered by the Inflation Reduction Act (IRA) and Infrastructure, Investment, and Jobs Act (IIJA).
These federal laws offer billions of dollars in grants, rebates and tax credits for state and local governments, non-profit entities and businesses for clean energy projects. State level policies like those modeled would provide more avenues for clean energy investment, allowing the state to better take advantage of these federal opportunities, leading to hundreds of millions of dollars in federal investment that would flow into Michigan. Much of that investment would be lost if these supportive state clean energy policies are not implemented.
What’s more, these economic benefits can be achieved while keeping household energy costs stable. The analysis found that because of clean energy policies that promote electric vehicle use and the electrification of home appliances and heating and cooling systems, the typical household would spend more on electricity but spend significantly less on gasoline and other fuels, leading to a decrease in total energy costs.
To illustrate how the private sector is already responding to the influx of federal funding and the prospect of additional state policies, as part of the report, Michigan EIBC surveyed and interviewed companies working in renewable energy, energy storage, electric vehicle charging, energy efficiency, construction and manufacturing. A majority of these companies plan to use federal grant opportunities from the IRA and IIJA to expand their business operations and workforce, with three-quarters planning to hire at least five more employees, and nearly half planning to hire 50 or more employees in the coming year.
These results show that clean energy policies are already driving economic growth and job creation, but also demonstrate the potential for even more investment and growth if the right policies are in place.
Michigan needs to establish policies that expand renewable energy and energy storage, allow Michiganders to generate their own electricity and protect their families from power outages, add charging infrastructure to enable more drivers to go electric, and improve the energy efficiency of our homes and businesses. As this report reveals, these policies would be a win-win for the state — reducing carbon emissions while also creating jobs, spurring economic growth and lowering energy costs.
A consortium of Minnesota electric cooperatives is preparing to apply for $970 million in federal funding that could help propel rural utilities toward the state’s 100% clean electricity target.
The state’s largest generation and transmission cooperative, Great River Energy, convened the group, which so far includes more than half of its members. The utilities are collaborating on an application for the U.S. Department of Agriculture’s Empowering Rural America, or New ERA, program.
The $9.7 billion program, created under the Inflation Reduction Act of 2022, is designed to help rural electric cooperatives pay for clean energy, carbon capture, energy storage and transmission projects. It represents the largest federal investment in rural electricity since the 1930s.
Great River Energy’s consortium includes proposals for solar, storage, distributed energy resource management systems and other initiatives. The program wants co-ops to propose “ways to get clean energy on the system to reduce the greenhouse gas emissions and improve resiliency and reliability,” said Jamie Stallman, energy conservation and optimization specialist for Great River Energy.
A new report released Wednesday by the climate policy advocacy group Evergreen Action highlights the opportunity that rural cooperatives have under New ERA and other federal programs.
“Rural America deserves a thriving clean energy economy that’s affordable, reliable, and carbon-free,” said report author and Evergreen energy policy transition lead Mattea Mrkusic. “The IRA offers a once-in-a-generation opportunity to strengthen [co-ops’] balance sheets and make clean electricity cheaper, cleaner, and more reliable for member-owners.”
The report details how generation and transmission cooperatives serving Minnesota could reduce or eliminate coal plants and provide members with less expensive electricity. The report said wind energy offers substantial savings over coal energy produced at Great River Energy’s two coal-fired plants.
Jeff Haase, director of member services, distributed energy resources and end use strategy for Great River Energy, said the money will help the company comply with the state’s new law requiring that utilities generate 100% of their electricity from carbon-free resources by 2040. The utility has a goal of being 90% carbon-free by 2037 and reducing natural gas generation to 5% of its load.
“GRE is well positioned to meet our goals, but we’re looking at the funding opportunities through the federal government as a way of helping to reduce the costs for our members,” Haase said.
Mrkusic said cooperatives could receive even more federal support by stacking incentives such as adders available if they serve low-income communities. Federal money could pay for 60% of a project’s costs in low-income areas, she said.
“Rural coops serve 92% of the ‘persistent poverty’ counties in the nation, so this is an equity issue, too,” Mrkusic said.
Minnesota Rural Electric Association CEO Darrick Moe said he and his organization’s members like the influx of federal money but are focused on projects that increase affordability and reliability.
Evergreen Action’s report calls for closing natural gas plants, a goal Moe does not endorse.
“I think this idea that we can only rely on solar and wind in the short term is not true,” Moe said. “I want to be careful not to say anything that contributes to that sentiment.”
Applications for the New ERA program are due in September. Stallman said planning has intensified as the deadlines approach. He continues to speak with cooperatives who have not joined and checks in with federal agricultural officials to let them know the proposal’s status and to hear feedback.
Applying as a consortium offers advantages, he said. It allows federal officials to evaluate the portfolio of projects more efficiently, and also “eases the burden” on individual members.
Federal agricultural officials have told Stallman the agency wants “fully baked” projects that co-ops will begin once receiving grant or loan money. The consortium continues to speak to members about joining the consortium while preparing the application.
The Empowering Rural America program does not require matching grants, he said. The federal government could fund the consortium’s $970 million proposal entirely through a grant or a grant and low-interest loans, Stallman said.
Spokesperson Rob Davis said that Connexus Energy, the state’s largest electric cooperative, is working on its own application and also seeking other federal money for clean energy projects.
“Where there’s an opportunity to create more value for our members we will participate and pursue them,” Davis said.
The federal government has not said when it plans to announce grant and loan recipients.
Correction: Connexus Energy is working on its own application for the federal Empowering Rural America program. An earlier version of this story mischaracterized its application.
The third powerline was the last straw for Marla Britton.
Her and her husband’s 40-acre farm near Brainerd, Minnesota, is already framed by electrical wires on the east and south. When she learned of plans for a new project running along the north end of her property, she took action.
Britton wrote to state utility regulators and contacted the companies behind the planned Northland Reliability Project. The 180-mile line will eventually make it easier to move clean electricity between central and northern Minnesota.
Soon, a utility representative was at her doorstep to discuss her concerns and ideas for rerouting the line where it would have less impact on her and her neighbors.
“They listened to me and wrote down what I said,” Britton said. “They agreed it was way too much for my property.”
It’s yet to be seen how Britton’s feedback will be reflected in the final route, but the interaction illustrates the type of engagement that project backers say they are aiming for with the project. Taking the time today to listen to property owners and adjust plans in response to their concerns, they hope, will lessen the likelihood of drawn-out legal or political battles delaying the project later.
The utilities building the project, Minnesota Power and Great River Energy, are using a playbook informed by an infamous rural revolt against a transmission line project through central Minnesota in the 1970s. In addition to lawsuits to try to block that project in court, opponents held large rallies, blocked construction workers, and vandalized utility equipment.
Great River Energy’s vice president and chief transmission officer, Priti Patel, still recalls a senior executive years ago giving her a copy of “Powerline: The First Battle of America’s Energy War,” a book about the battle co-authored by the late U.S. Sen. Paul Wellstone, who was then a professor at Carleton College in Northfield, Minnesota.
The book describes what utilities should not do when developing large power lines, such as overusing eminent domain for land acquisition and dismissing the fears and concerns of rural citizens.
“I still have that [book] on my desk, because it’s a reminder … of the importance of active inclusion of voices of impacted landowners, particularly in rural Minnesota,” Patel said.
With the Northland Reliability Project, landowner engagement so far has included in-person and virtual open houses, phone calls, one-on-one meetings, handouts, emails, and an inclusive website. With a price tag of $970 million, the double-circuit, 345-kilovolt line is one of two Minnesota projects that has been fast-tracked by the regional transmission grid operator MISO for completion by the decade’s end.
The project largely follows the same path as existing smaller capacity transmission lines the utilities own, which could also help make it less controversial, said Beth Soholt, executive director of the Clean Grid Alliance, which advocates for transmission and clean energy.
“It’s just easier to site and probably construct. We’re hoping these early lines take less time to build,” Soholt said.
The two utilities combined have held 27 workshops in six months. They will continue throughout the year, reaching out to every township and municipality along the way, in addition to landowners, tribes, agencies, snowmobile groups and ATV clubs, and other organizations, according to Patel. So far, no organized opposition has emerged.
A few landowners and agencies have had concerns, said Jim Atkinson, Minnesota Power’s environmental and real estate manager, but planners have been proposing workarounds that could satisfy them. The input from stakeholder meetings “has informed the design of our route quite a bit,” he said.
Christina Hayes, executive director of Americans for a Clean Energy Grid, said the two Minnesota utilities are following the best practice of early stakeholder engagement to avoid later potential litigation. Hayes said the gatherings allow power companies to meet opposition and change routes before presenting to public utility commissions.
“The Midwest is a model for the rest of the country,” Hayes said. Utilities have “fostered the sense of ‘a rising tide lifts all boats’ and ‘we’re all in this together,’ and that has done a lot to keep the lights on in the Midwest as these emergency electricity situations have arisen around extreme weather.”
Morrison County Commissioner Greg Blaine, a Stearns Electric Association and Great River Energy board member, has been representing the project at community meetings. He said the constituents and customers asked about rolling blackouts and polar vortexes that have affected the grid over the last few years. The outreach meetings “help answer some of the questions out there,” Blaine said.
He tells them the transmission project could be an economic engine for the county that will make development in this area easier. “This addresses a need,” he said.
That’s not to say the utilities and landowners have a harmonious relationship. St. Cloud attorney Nicholas Delaney said after landowners agree to easements for transmission lines, utilities sometimes play hardball during negotiations on issues such as severance damage. Landowners want utilities to help cover damage on areas outside of easements that may suffer from heavy machinery used to install pools and lines, Delaney said.
Minnesota law requires utilities to buy all or part of the properties of landowners who don’t agree to easements. Delaney said utilities move routes and try to establish good relationships to avoid the law because of the expense, and “because they’re not in the business of buying and selling land.” Under the federal Uniform Relocation Act, utilities could also have to pay moving fees, replacement housing differential costs and other charges of farmers who can prove they are being displaced by power lines.
The utilities will soon file a certificate of need and route permit with the Public Utilities Commission. If all goes according to plan, construction will start in 2027.
Correction: Minnesota Power and Great River Energy had not yet filed for a certificate of need and route permit as of the time of publication but were expected to do so soon. An earlier version of this story misstated the application’s status.
Large cross-country transmission lines carrying clean energy from remote rural areas to population centers will be a key strategy for reducing emissions.
But as a project in Minnesota illustrates, the grid puzzle is more complicated than that.
Connecting central and northern Minnesota, the Northland Reliability Project will reinforce the state’s electric grid with new transmission lines as fossil fuel-powered plants close and utilities rely on more clean energy generation.
The Midcontinent Independent System Operator, Inc., known as MISO, chose the Northland Reliability Project as one of 18 transmission projects in a more than $10 billion first tranche budget. The 180-mile-long project has the initial group’s second-highest budget: $970 million.
Transmission has been a challenging issue nationwide as utilities and customers transition to producing and consuming more clean energy. Rich in wind power, the Midwest is no different, with MISO having seen developers pull projects because of a lack of transmission.
Allete subsidiary Minnesota Power and generation and transmission cooperative Great River Energy will build the project from central Minnesota to the mining-intensive Iron Range. The project adds double-circuit 345-kilovolt transmission lines to a route where smaller lines will still operate.
Beth Soholt, executive director of Clean Grid Alliance, said Minnesota Power and Great River Energy wanted the project to improve reliability in their territories. The project “supports and beefs up the regional grid in this particular location,” she said. Because it crosses the borders of the utilities, they will build and own it, but MISO will pay for it.
Northland’s route runs near two retiring fossil plants and Xcel Energy’s Monticello nuclear energy plant. Owned by Minnesota Power, the Boswell Energy Center in Cohasset near the northern terminus will close in phases by 2035. The other coal plant, the Xcel-owned Sherburne County Generating Station also known as Sherco, will close by 2030.
Dan Gunderson, Minnesota Power’s vice president for transmission and distribution, said the Northland project “will be a critical element to ensure we have regional stability for our large customers in the northern part of the state,” he said.
Unlike most regional utilities primarily serving commercial and residential customers, Minnesota Power’s most significant customer base consists of mines that often draw enormous amounts of electricity for operations. Gunderson said the line would be a key element in meeting demand, especially in winter when it grows significantly.
Great River Energy’s vice president and chief transmission officer, Priti Patel, explained the challenge: “When we think of this energy transition, it’s not just about bringing in transmission to serve more renewables; it’s also about the fact that generation is retiring and retirements create the need for new transmission,” she said.
When baseload generation decreases, the geographical disparity of power sources increases and voltage stability concerns grow, Patel said.
The transmission line “is not directly connecting right now to any renewable generation specifically,” she said. “But part of this energy transition is maintaining reliability. And when you have baseload plants retiring and more renewables connecting, you need transmission to maintain the stability of the system.”
At least at the southern end of the line, Northland links to a Sherco substation. Xcel will be building a 460-megawatt solar plant at its Sherco site to generate electricity for the region and the Northland will likely carry some of it to customers. Earlier this year, Xcel proposed another solar array to bring the total output to 710 megawatts.
Soholt said MISO calls the first tranche investments “least regrets” transmission lines because studies demonstrated that the projects showed the most significant promise of adding reliability and resiliency, she said. Any new transmission will only help Minnesota meet its goal of generating electricity from carbon-free sources by 2040, Soholt said.
MISO’s long-range planning document points out that lines from south to northern Minnesota are 115 kV and 230 kV, not enough capacity for Minnesota Power to comfortably serve customers with power coming from the Twin Cities.
“This large geographical disparity in generation and weak transmission causes voltage stability concerns for a majority of the Minnesota system north of the Twin Cities,” MISO wrote.
No organized opposition has emerged, but Red Wing attorney Carol Overland has misgivings. A persistent critic of transmission line projects for decades, she contends that transmission capacity will grow as coal plants shut down. “There’s a lot of the system already existing that will have opened up capacity when coal plants shut down,” Overland said.
Utilities earn more profits from building transmission than from generating and selling electricity, she said, making them proponents of large projects. Since transmission costs fall to ratepayers, utilities benefit without taking much financial risk, Overland said.
Overland suggested that generating clean energy closer to where it will be consumed would decrease the need for transmission and offer a more stable grid. For the same amount of money that will be spent on transmission, “you could get a lot of solar [installed] where it is needed,” Overland said. “But [utilities] can’t get a rate of return on that.”
Construction is scheduled to begin in 2027 with the transmission project to be complete and carrying electricity by 2030.
Over the last five years, wind and solar farms have grown exponentially across Texas, transforming the state’s power grid and generating more electricity than ever this year amid the searing summer. The story has been different in El Paso, however.
Last month, solar farms across Texas produced more electricity in June than they did in all of 2018. Wind and solar farms combined last year to produce 31% of the electricity on the power grid that covers most of Texas outside of El Paso – which is operated by the Electric Reliability Council of Texas, or ERCOT – and that’s grown to 35% of the state’s power through the first half of this year.
Yet in the Borderland, less than 3% of the electricity El Pasoans used last year came from renewable energy sources, a figure that pales in comparison to other utilities across both Texas and New Mexico.
A top El Paso Electric executive cautioned against comparing figures from EPE, a monopoly utility overseen by state regulators, to ERCOT, which is a deregulated, competitive market that electricity generators sell power into. Even so, El Paso Electric has initiated plans to shutter some of its aging natural gas power plant units and rely more on solar energy.
Last month, EPE began receiving power from the new Buena Vista solar farm, a 120-megawatt, 900-acre sea of solar panels outside of Chaparral, New Mexico. It’s the utility’s biggest-ever solar facility.
And El Paso Electric is planning to develop by 2025 four other big solar farms with 580 megawatts of capacity. The utility is also adding batteries at some of the solar farms to capture solar energy at midday and discharge the power onto the grid in the evening after the sun sets. One megawatt is enough to power a few hundred homes at once, depending on the time of day and temperature.
“We have a plan to get caught up,” Jessica Christianson, EPE’s vice president of sustainability and energy solutions, told El Paso Matters. “And I think that it’s a really methodical plan that takes into consideration the importance of clean energy and the environmental impact of our operations. But concurrently gives us an affordable and reliable solution.”
El Paso’s electricity today is far more likely to come from either the Palo Verde nuclear power plant west of Phoenix – the largest power plant in the country – or from EPE’s fleet of four local natural gas-fired power plants. Nuclear and gas-fired plants produced 84% of the region’s electricity in 2022, according to El Paso Electric.
“Resource mixes are variable between utilities,” said Jon Rea, a senior associate focused on carbon-free electricity with the Rocky Mountain Institute, a nonprofit energy research group based in Colorado. “But El Paso does stand out for having very little wind and solar in comparison to the rest of Texas.”
El Paso Electric in 2016 closed its only coal plant and shifted to heavier reliance on natural gas, which emits about half as much of the greenhouse gas carbon dioxide as coal does. Meanwhile, across the ERCOT power grid, coal accounts for a shrinking but still significant portion of the state’s energy; last year coal-fired power plants produced almost 17% of the electricity generated in Texas.
“That was our big first step in our generation portfolio transition,” Christianson said of getting off of coal. “We really made that decision to get rid of the worst first.”
EPE today relies on the nuclear plant for about 45% of its power supply; across the rest of Texas, the state’s two major nuclear plants generated about 10% of its electricity. Nuclear power plants don’t produce greenhouse gas emissions that contribute to climate change – so including nuclear, EPE gets almost 48% of the region’s electricity from “carbon-free” sources.
Still, the amount of solar power generated by El Paso Electric remained virtually unchanged from 2016 through 2022. But over that same time, solar generation across the Texas grid multiplied several times over, from 420 gigawatt-hours in 2016 to over 24,000 gigawatt-hours last year.
El Paso Electric’s emissions “have generally been lower than the industry average,” Rea said, citing the utility’s lack of coal and its big reliance on nuclear power. “But that hasn’t changed much over time. They haven’t made a lot of progress or change in the last decade, and competing utilities that we see making a transition have been adding more wind and solar.”
While wind farms contributed a quarter of the power generated across ERCOT last year, El Paso Electric gets zero electricity from wind farms.
When EPE unveiled the Buena Vista solar farm in April, Christianson said solar farms are cheaper for the utility to receive power from than wind farms. That’s because the windiest areas of New Mexico are outside of EPE’s service territory, she said, and the utility would have to build costly transmission lines to ferry electricity from faraway wind farms into El Paso.
One mile of transmission towers and wires can cost a few million dollars to build.
“It’s not that we’re not pursuing wind, we just are doing this solar first,” Christianson told El Paso Matters in April.
“The quality of the wind that you want for generation, it’s a little bit outside of our service territory. So to make that cost-competitive is a little bit more of a challenge, because there will be necessary transmission upgrades,” she said.
By comparison, the other major investor-owned utilities in New Mexico – PNM and Xcel Energy – as of the end of 2022 maintained a collection of wind and solar farms far greater than El Paso Electric’s portfolio. PNM receives power from solar and wind farms totaling 1,040 megawatts of capacity, and Xcel Energy’s portfolio in its Texas and New Mexico service territory includes over 2,700 megawatts of mostly wind and some solar.
And CPS Energy in San Antonio gets power from a portfolio of almost 1,500 megawatts of wind and solar farms. And almost half of the electricity that city-owned Austin Energy generated last year came from solar and wind farms; its portfolio of renewables tops 2,700 megawatts. Austin Energy and CPS are city-owned utilities, but they also own their power plants and distribution systems like EPE does.
El Paso Electric’s current portfolio of solar farms, including the Buena Vista project that began operating in June, totals 239 megawatts.
EPE hasn’t “been a laggard in terms of emissions,” Rea of the Rocky Mountain Institute said. “But in terms of being climate-aligned with a low-carbon future, they are falling behind in making their transition.”
However, shifting off current power sources to renewables like wind and solar isn’t simple or cheap, said Ed Hirs, an energy fellow at the University of Houston.
One of the solar farms El Paso Electric is developing, a 150-megawatt solar facility in Fabens, is slated to start producing power in May 2025. EPE said the site will cost $218 million to develop and will raise the average El Paso household’s monthly electric bill by $2.68.
By comparison, a new 228-megawatt natural gas power plant unit that EPE is currently building – the Newman 6 unit near Chaparral – will cost at least $193 million, and raise El Paso households’ power bills by a minimum of $3 per month on average.
Transitioning to cleaner energy sources is “a capital expense that somebody’s going to have to take on,” Hirs said.
“If El Paso Electric says, ‘Hey, we’re going to go all green – which would make some people excited – that’s going to have a very high, significant cost,” he said.
There are cost and reliability concerns with natural gas, as well. The price for the natural gas that fuels a power plant can swing dramatically – whereas wind and solar farms don’t need fuel, water or as many employees to operate.
Household electric and gas bills shot up last year after the market price for natural gas doubled last summer from a year earlier. And natural gas supply lines froze up across much of Texas during the deadly February 2021 winter storm that blanketed the state, choking off the supply of gas and sending the price skyrocketing as utilities competed to buy the scarce fuel.
The shortage of natural gas prevented power plants from running and exacerbated the power shortage, which El Paso avoided. But El Pasoans are still paying extra fees on their monthly gas bills to pay off the high-priced natural gas purchased during the winter storm.
Still, Hirs argued that EPE has made progress by ditching coal in favor of cleaner-burning natural gas and nuclear energy. And he pointed out the EPE maintains a reliable system; El Pasoans typically experience fewer power outages than customers of most other similarly-sized utilities in Texas and New Mexico.
Rea said government incentives funneled through the federal Inflation Reduction Act and low-cost loans have made renewable energy investments more economical and could accelerate EPE’s shift to relying on sources of energy that produce less pollution. For reference, after the Newman 6 unit starts operating later this year, it will emit around 790,000 tons of carbon dioxide into the El Paso region’s air each year.
“A project that previously would have happened in 2030 or 2035 now makes economic sense to do in 2025 to 2030,” Rea said. “So it just moves up the timeline of making those investments in renewables because of all the tax incentives.”
Both Hirs and Rea agreed that within a decade, wind, solar farms and battery arrays will likely dominate the power grids in Texas and New Mexico, alongside some natural gas power plants on hand to help ensure there’s always enough electricity available.
Christianson said EPE is taking “meaningful” steps to generate more clean electricity in the coming years.
“Give us the opportunity to execute on this plan,” she said, “and you’re going to be really impressed with what you see from El Paso Electric in the next couple years.”
This article first appeared on El Paso Matters and is republished here under a Creative Commons license.
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