The following commentary was written by Jesse Velazquez, Climate Justice Manager at the Ohio Environmental Council. See our commentary guidelines for more information.
In his victory speech, President-elect Donald Trump promised to further boost “liquid gold,” also known as oil and gas. Today, oil and gas production is at record highs and continues to grow. As the industry expands, so do concerns about methane pollution.
The primary component of natural gas is methane, a potent greenhouse gas that warms the planet more than 80 times as much as carbon dioxide over 20 years. It’s also a significant contributor to smog and public health issues like asthma and respiratory disease, disproportionately affecting vulnerable communities. Yet, efforts to reduce methane emissions present a rare win-win opportunity: they not only curb pollution but also create jobs and foster innovation.
Take Pennsylvania, one of the largest natural gas producers, for example. By adopting innovative methane mitigation strategies, the state is reducing harmful emissions from oil and gas operations while creating jobs and fostering a cleaner, more sustainable energy future. This balanced approach showcases how economic growth and environmental responsibility can go hand in hand, offering a model that Ohio should replicate.
According to the 2024 State of the Methane Mitigation Industry Report, developing and implementing technologies to cut methane pollution would create jobs ranging from manufacturing leak-detection equipment to technicians skilled in repairing faulty infrastructure. Pennsylvania saw a 22.2% growth in methane mitigation companies over the last three years. Since 2014, the industry has expanded by 65% with the state now hosting 33 methane mitigation companies. In fact, Pennsylvania is now home to 8.5% of the total employee locations in this sector nationwide.
These good-paying, family-sustaining jobs bolster local economies while addressing critical environmental challenges. And the opportunity for Ohio is immense.
The benefits extend far beyond jobs. Reducing methane emissions means less wasted energy. Nationally, oil and gas companies emit enough methane waste annually that could be utilized to meet the energy needs of millions of homes. Capturing the lost gases would translate directly into increased efficiency and cost savings. For a state like Ohio, with its large-scale oil and gas operations, this represents a tangible economic benefit.
This isn’t just about economic gains. Methane mitigation is also a crucial climate strategy. The U.S. EPA’s Section 111 Methane Rule, finalized a year ago, set robust federal standards to limit methane emissions from oil and gas operations. While essential, this rule relies heavily on state-level implementation to achieve its full potential. States like Ohio have a chance to lead by adopting and building on these standards, aligning economic growth with environmental stewardship.
And we know clean air and economic growth are priorities that transcend party lines, as evidenced by the broad coalition of businesses, environmental advocates, and community leaders rallying behind these initiatives.
Ohio is at a crossroads. We can continue business as usual, or we can follow Pennsylvania’s lead, investing in proven technologies and practices that cut emissions, prevent waste, protect public health, and drive economic growth.
By prioritizing methane mitigation, the state can chart a path that aligns with both the nation’s energy ambitions and the pressing need for climate action. This is not just a moral imperative but an economic one that promises cleaner air, healthier communities, and a thriving workforce for generations to come.
By Joel Jaeger, Katrina McLaughlin, Lori Bird and Karl Hausker Building a clean, reliable, cost-effective power grid will require many different types of energy. The bulk will come from solar and wind; but since these aren’t available 24/7, 365 days a year, they must be paired with a smaller amount of clean, “firm” power that’s always available when needed. …
Electric power lines. (Scott Olson | Getty Images)
The Sierra Club of Wisconsin says that the decision to delay the retirement of a Columbia County coal power plant until 2029 to consider converting it to a natural gas plant will harm the environment and expose nearby residents to harmful emissions.
The Columbia Energy Center was initially set to be closed this year, but two years ago the plant’s retirement was delayed until 2026. In a statement on Wednesday, the co-owners of the plant, Alliant Energy, Madison Gas and Electric and Wisconsin Public Service, said keeping the plant open another three years will allow them to “explore converting at least one of Columbia’s units to natural gas.” The companies added that the decision will allow them to maintain the reliability and affordability of energy.
Utility companies have said that using natural gas allows them to keep providing power while moving away from more harmful fuels such as coal.
“Natural gas plays an important role in enabling the ongoing transition toward greater use of renewable resources by providing a flexible, dispatchable resource to serve customers reliably and affordably when necessary,” the companies said in the statement.
But environmental advocates lamented the decision, which will keep coal burning at the plant south of Portage for three more years than previously expected. On Friday, the Sierra Club criticized the use of natural gas at all.
The environmental group said that gas plants are vulnerable to failure, especially in places that experience harsh winters. The environmental group accused the companies of making the decision to boost their own profits.
The group also said that emissions from methane gas-burning plants are more harmful to the environment than coal plants and pose health risks to neighbors.
“We are enraged that Alliant, MG&E, and WPS have once again kicked the can on the Columbia Energy Center’s retirement date, and further exasperated with their considerations to convert the station to deadly methane gas,” the Sierra Club’s Cassie Steiner said in a statement. “Make no mistake: methane gas is not a ‘transition fuel’; it’s a way for utilities to keep exploiting captive customers for an even greater corporate profit while polluting those same communities they are supposed to serve.”
“Clean energy sources can reliably meet customers’ needs at a far cheaper cost and at no risk to their health,” Steiner continued. “Utilities like Alliant have continued to backpedal on their clean energy commitments and then hold their customers hostage to pay for their poor decisions. We simply cannot afford to extend our dependency on costly, polluting fossil fuels like coal and methane gas.”
Hydroelectric energy is the “backbone of clean power,” but an urgent need to improve efficiencies is driving engineers to explore a whirlwind of options Among alternative energy solutions, wind, solar, and hydrogen capture the majority of attention. Yet the combined output from these sources pales in comparison to that of hydroelectric power. Producing more than …
As a state committee studies ways to wean Rhode Island off of natural gas, several of its members want the group’s final report to dismiss one potential pathway as wholly unrealistic.
Switching to renewable natural gas or other alternative fuels appears to be neither a feasible nor a financially viable solution at this time, say multiple stakeholders who have commented on a draft outline of a report a consulting group prepared for Rhode Island regulators.
RNG is derived from biomass or other renewable resources. It is a biogas, captured from the decomposition of organic matter, such as animal manure or food waste.
Many gas utilities around the country are pushing for RNG as part of the solution to lowering greenhouse gas emissions. But Michael Walsh, a partner at Groundwork Data, a clean energy consultancy that worked with the Conservation Law Foundation and the Sierra Club in the committee process, told the Energy News Network that “we don’t see a lot of viability with the RNG pathway,” both because of limited availability and because it is much more expensive then fossil fuel gas to produce.
While RNG is interchangeable with conventional natural gas, “realism about the availability and cost of alternative fuels for the gas system is necessary” for the planning process, wrote Nicholas Vaz, Rhode Island special assistant attorney general, in his comments on the draft.
Vaz cited a 2019 study prepared for the American Gas Foundation that looked at RNG production potential by 2040, based on the availability of source materials and utilization. Based on those findings, Vaz concluded that the amount of RNG available by 2050 would only allow for about 17% of Rhode Island households to remain connected to the gas system.
Currently, more than half of Rhode Island homes receive natural gas service.
The state Public Utilities Commission established the stakeholder committee as part of its “Future of Gas” docket, an investigation of the future of the regulated gas distribution business in Rhode Island. That docket was opened in 2022 in response to the passage of the state’s Act on Climate, which mandates a 45% reduction in greenhouse gas emissions below 1990 levels by 2030, 80% by 2040, and net-zero by 2050.
The natural gas system operated by Rhode Island Energy accounts for almost 40% of statewide emissions. So the PUC, which regulates the utility, is in the tricky position of having to craft a plan for getting commercial and residential customers off natural gas, finding a way to pay for it, and ensuring that consumers aren’t harmed in the process. Regulators will use the committee’s report to help inform the strategy it lays out.
The neighboring state of Massachusetts is a little farther along in that process; its state Department of Public Utilities issued an order last December outlining a strategy for getting the state off natural gas.
While utilities there initially pushed for a plan that was heavily reliant on RNG, regulators ultimately rejected that approach, citing concerns about availability, cost and whether such alternative fuels will actually lead to a reduction in emissions.
To some extent, Massachusetts’ work to date helped inform the committee process in Rhode Island, Walsh said.
“We had a lot of Massachusetts folks in the room to share lessons learned,” he said. “We at least got through some of the questions faster.”
Ben Butterworth, director of climate, energy and equity analysis for the nonprofit Acadia Center, told ENN his organization would like to see Rhode Island prioritize much of what is in the Massachusetts strategy: a focus on electrification and energy efficiency, disincentivizing further expansion of the gas system, and pilot programs focused on the strategic decommissioning of the gas system.
The PUC must also consider how to fund the transition, Butterworth noted. Vermont and Massachusetts are pursuing a clean heat standard as a funding mechanism for climate goals, while New York is pursuing a cap-and-invest approach.
“Finding that mechanism is critical, and the report should include at least those options,” Butterworth said.
At the same time, the report should include a discussion of possible mechanisms to protect low-income ratepayers from “the inevitable initially increased costs of electrification,” urged Jennifer Wood, executive director of the Rhode Island Center for Justice, in her comments on the draft.
These might include capping the amount a household pays for electricity as a percentage of their income; rate reforms; and assistance programs to defray the costs of installing electric heat pumps.
“Low-income utility customers living in rented homes that are least well equipped for energy efficiency are already most harmed by the social effects of climate change,” Wood wrote. “The only way to ensure that they will not be doubly harmed by unsustainably higher utility bills during the transition…is to decouple income-eligible consumers’ energy costs from the near-term impacts of necessary, but initially more costly, electrification.”
The committee is expected to issue a final report with its findings and recommendations to the PUC by the end of the year.
North Carolina regulators on Friday accepted Duke Energy’s controversial plan for curbing carbon pollution, a blueprint that ramps up renewable energy and ratchets down coal power but also includes 9 gigawatts of new plants that burn natural gas.
The biennial plan is mandated under a 2021 state law, which requires Duke to zero out its climate-warming emissions by midcentury and cut them 70% by the end of the decade.
The timing of the order from the North Carolina Utilities Commission, two months ahead of schedule, caught many advocates by surprise. But its content did not: it hewed closely to a settlement deal Duke reached this summer with a trade group for the renewable energy industry; Walmart; and Public Staff, the state-sanctioned ratepayer advocate.
But critics were dismayed by regulators’ abdication of the 2030 deadline. The ruling said Duke no longer needed a plan to make the reductions by decade’s end, instead telling it to “pursue ‘all reasonable steps’ to achieve the [70%] target by the earliest possible date.”
“Major step back on climate,” Maggie Shober, research director at the Southern Alliance for Clean Energy,” wrote on X, the website formerly known as Twitter, adding, “for those that say it couldn’t be done, Duke had a 67% reduction by 2030 in its 2020 [long-range plan.] The utility industry generally, and Duke in particular, has had opportunity after opportunity to do better. They chose not to, and here we are.”
“Duke’s plan isn’t even compliant with the latest EPA regulations related to greenhouse gas pollution,” David Rogers, deputy director of the Sierra Club’s Beyond Coal Campaign, said in a statement.
Concerns about the Biden-Harris rules, along with doubt that the natural gas plants could be converted to burn carbon-free hydrogen, appeared not to persuade regulators.
“The Commission acknowledges that there are uncertainties and risks associated with new natural gas-fired generation resources, but this is true of all resources,” the panel wrote.
On the contrary, regulators believe Duke can make use of gas plants after the state’s 2050 zero-carbon deadline, even if clean hydrogen doesn’t pan out.
“Accordingly,” the panel said, “the Commission determines that a 35-year anticipated useful life of new natural gas-fired generation and its assumed capital costs are reasonable for planning purposes.”
The greenlight for the gas infrastructure is not absolute, commissioners emphasized in their order, since Duke still must obtain a separate permit for the facilities. But advocates still bemoaned the anticipated impact on customers.
“This order leaves the door open for Duke Energy to stall on carbon compliance in order to develop additional resources, like natural gas, that largely benefit their shareholders over ratepayers,” Matt Abele, the executive director of the North Carolina Sustainable Energy Association, said via text message.
‘Positive step’ for offshore wind
Still, Abele and other advocates acknowledged the plan’s upsides, including its increase in renewables like solar and batteries. The 2022 plan limited those resources to about 1 gigawatt per year; this year’s version increases the short-term annual addition to about 1.7 gigawatts.
Regulators’ decision to bless 2.4 gigawatts of offshore wind by 2034 and call for Duke to complete an “Acquisition Request for Information” by next summer also drew measured praise.
“This order is an overall positive step for offshore wind,” Karly Lohan, North Carolina program manager for the Southeastern Wind Coalition, said in an email, adding, “we still need to see Duke move with urgency and administer the [request for information] as soon as possible.”
With regulators required to approve a new carbon-reduction plan for Duke every two years, advocates are already looking ahead to next year, when the process begins anew.
“Proceedings in 2025 present another chance to get North Carolina back on track to achieving the carbon reduction goals as directed by state law,” Will Scott, Environmental Defense Fund’s director of Southeast climate and clean energy, said in a statement.
“By accelerating offshore wind and solar, the Commission could still set a course for meaningful emissions reductions from the power sector that are fueling the effects of climate change, including dangerous and expensive storms like Hurricane Helene.”
And like Scott, David Neal, senior attorney with the Southern Environmental Law Center, isn’t giving up on the state’s 2030 carbon-reduction deadline, the commission’s latest order notwithstanding.
“We’ll continue to push for the clean energy future that North Carolinians deserve and that state law and federal carbon pollution limits mandate,” he said in a statement.
Nearly a year after Massachusetts regulators laid out a vision for the state’s evolution from natural gas distribution to clean energy use, lawmakers are coalescing around legislation that would start converting principles into policy.
The wide-ranging climate bill includes several provisions that would allow utilities to explore alternatives to gas and empower regulators to place more limits on the expansion and continuation of natural gas infrastructure, changes that supporters say are critical to a successful transition away from fossil fuels.
“This bill is a major first step in empowering [regulators] to do something rather than just rubber stamping the utilities’ plans,” said Lisa Cunningham, co-founder of ZeroCarbonMA.
Natural gas is currently the primary heating source for half the homes in Massachusetts, a number that needs to drop if the state is going to meet its ambitious climate goal of net-zero emissions by 2050, advocates and state leaders say. In 2020, the state department of public utilities opened an investigation into the role natural gas utilities would play in the transition to cleaner energy. In December 2023, the department issued a lengthy order concluding that the state must move “beyond gas” and outlining a broad framework for making the shift.
Lawmakers attempted to start turning these general ideas into binding law earlier this year, but the legislative session closed at the end of July before the Senate and House reconciled the differences between their versions of a climate bill. Legislators returned to work this fall and hammered out an agreement, and the Senate passed the resulting bill last month. The House speaker has said the body will vote when it returns to formal session later this year. The bill is generally expected to pass and be signed into law.
“A lot of people were skeptical we’d get a bill at all, but I’m happy with where this bill ended up,” said Kyle Murray, Massachusetts program director for climate nonprofit Acadia Center. “It shows a step toward that needed urgency.”
At the heart of the bill’s energy transition provisions is a change to the definition of a natural gas utility that allows the companies to also provide geothermal power. Networked geothermal — systems that draw heat from the earth and deliver it to a group of buildings — is widely seen as a promising alternative to natural gas, and both National Grid and Eversource have pilot projects in the works. However, current law prevents the utilities from pursuing such projects without specific authorization from regulators. The climate bill would remove this barrier, making it easier for gas companies to explore new approaches to business.
“The gas utilities deeply need a new business model that can help them step into the future,” said Audrey Schulman, founder of climate solutions incubator HEETlabs. “That allows them to potentially evolve.”
This definition change supports other provisions aimed at slowing the expansion of natural gas use in the state. The bill would end the requirement that natural gas utilities provide service to any customer in their service area who requests it, with few exceptions. Under the new law, utilities could decline these requests when other alternatives are available.
The bill would also allow regulators to consider the impact of emissions when deciding whether to approve requests to expand natural gas service into new communities. In 2023, the state approved a request to bring gas service to the central Massachusetts town of Douglas. Regulators at the time noted that the decision works against the state’s goal of phasing out natural gas, but said the law gave them no choice but to approve the plan. Provisions in the climate bill would untie regulators’ hands in such cases in the future.
“The [Department of Public Utilities] can consider the public interest, including climate, it doesn’t have to say yes to more gas service,” said Amy Boyd Rabin, vice president of policy at the Environmental League of Massachusetts. And the inclusion of geothermal in gas utilities’ definition means “now there’s also something else to offer the customers.”
Another major element of the bill would reform the state’s Gas System Enhancement Plans program, which encourages utilities to repair or replace pipes in the state’s aging and leak-prone natural gas distribution system. Clean energy advocates have often argued that these plans are problematic, investing billions of ratepayer dollars into shoring up a system that is increasingly obsolete. The climate bill would allow utilities to choose to retire segments of pipe rather than fixing them.
“For the first time ever they are able to look at a pipe and say, ‘You know what, this is not worth the cost,’” Murray said. “We don’t want ratepayers shouldering the burden for a lot of stuff that’s not going to be useful in five to 10 years.”
Environmental advocates praised the bill’s gas provisions, and are already focusing on what more there is to be done. Several would have liked to see a more aggressive phasing out of Gas System Enhancement Plans, with a specific end date. Others champion an expansion of a pilot program that allows cities and towns to ban fossil fuel use in new construction and major renovations.
“There is no reason why communities that want to enact this via home rule petition should be restricted from enacting the will of their constituents,” Cunningham said.
In the meantime, advocates are ready to see the climate bill turning into reality.
“There’s a lot of good stuff in there that will do a lot of good for the commonwealth,” Boyd Rabin says.
A prospective buyer’s recent commitment to reinvest in a Gary, Indiana, steel plant sought to address union and government leaders’ worries about the sale’s potential impact on jobs and U.S. steelmaking capacity.
The plan to extend the life of the country’s largest and most carbon-emitting coal-fired blast furnace, however, has also heightened concerns from Northwest Indiana residents most affected by the facility’s air pollution.
“This is not acceptable,” said Susan Thomas, director of legislation and policy for Just Transition Northwest Indiana. “We now have technology for doing this much more sustainably.”
A study released Monday quantifies the public health threat highlighted by local clean air advocates, linking the Indiana plant to dozens of annual emergency room visits and premature deaths, as well as thousands of asthma attacks.
Japan-based Nippon Steel is seeking approval from U.S. regulators for a $15 billion acquisition of U.S. Steel, the storied domestic steelmaker whose facilities include the Gary Works plant in Northwest Indiana, along with others in Ohio, Michigan and Pennsylvania, key battleground states where the proposed sale has been a subject of presidential campaigning. Vice President Kamala Harris and former President Donald Trump oppose the sale, as does President Joe Biden.
Much of the public discussion around the proposed sale has centered on its economic and national security implications, but those living near the plant have different concerns and demands. They say they’ve suffered for too long from steel industry pollution, and they only want Nippon as a neighbor if the company installs a new type of furnace that burns with lower or even zero emissions.
“I would love to see Gary Works transform to green sustainable steel, bringing more jobs, cleaning up the area, that would be an amazing win-win,” said Libré Booker, a librarian who grew up near the mill. “The people have lived under these conditions for far too long. It’s definitely time for a change.”
Gary Works is the largest integrated steel mill in North America, employing about 2,200 people. Northwest Indiana is also home to two other steel mills — Burns Harbor and Indiana Harbor — and two coke plants that turn coal into the high-density raw material for steel.
The populations in a three-mile radius of the Gary Works and Indiana Harbor steel mills are 96%-97% people of color, and almost two-thirds low-income people. The new study by Industrious Labs, a nonprofit focused on emissions reduction, used the EPA’s COBRA model to find emissions from the Gary Works plant likely are linked to 57-114 premature deaths, 48 emergency room visits and almost 32,000 asthma attacks each year.
The report cited the mills’ and coke plants’ emissions of sulfur dioxide, nitrogen oxides, carbon monoxide, particulate matter, and lead, all pollutants with direct impacts on public health. Gary Works is the number one emitter of PM2.5 particulate matter in the state, according to the company’s self-reported data analyzed by Industrious Labs.
Industrious Labs steel director Hilary Lewis said the results bolster the demands of clean steel advocates, who want to see coal-fired blast furnaces replaced by direct-reduction iron, or DRI, furnaces powered by hydrogen made with renewable energy, known as green hydrogen.
Booker was among 15 locals who participated in a recent “Sustainable Steel Community Cohort” run by Industrious Labs, attending five workshops learning about the science and policy of cleaner steel.
Green hydrogen, green steel
Green hydrogen is still not produced in large quantities anywhere in the U.S., and all the hydrogen currently produced in the country would not even be enough to power one steel mill, noted Seth Snyder, a partner in the Clean Energy Venture Group, at a recent conference in Chicago focused on clean hydrogen.
But DRI furnaces can be powered by natural gas, which results in much lower emissions than coal. Cleveland Cliffs — which owns the Indiana Harbor and Burns Harbor mills — is transforming its Middletown, Ohio steel mill to gas-burning DRI with the help of a $500 million incentive under the Inflation Reduction Act. The company says the conversion will make it the steel mill with the lowest emissions in the world.
With some modifications, DRI furnaces can burn a blend of natural gas and hydrogen or almost entirely hydrogen, experts say, meaning investment in a gas-burning DRI furnace could be a step on the way to “clean steel.” Lewis and other advocates, however, say gas-burning furnaces are not their goal, and they want the industry to transition off fossil fuels entirely.
Hydrogen can be blended into fuel for traditional blast furnaces too, but the maximum emissions reductions that can be achieved that way are 21%, according to a paper on hydrogen-powered steel production in Europe by the Norwegian non-profit science organization Bellona.
Nippon has announced it would invest $300 million in restoring the aging blast furnace at Gary Works, keeping it running for another 20 years. Installing a DRI furnace, meanwhile, typically costs over $1 billion.
“There is a gap,” said Lewis. “But these companies have the funding available. They have the money to make these decisions, they’re just choosing not to.”
Incentives for change
The IRA incentives tapped by Cleveland Cliffs are no longer available, but this summer California U.S. Rep. Ro Khanna introduced the Modern Steel Act, which would provide $10 billion in low-cost loans and grants, plus tax breaks and other incentives for new and revamped low-emissions steel mills, including hydrogen-fueled DRI.
Separately, lucrative tax credits soon to be available for “clean hydrogen” under the IRA could also make hydrogen-powered steel more financially viable. The specific rules for the tax credit — known as 45V — are still being finalized, amid controversy over what should qualify a project’s hydrogen as “clean.”
“There are a number of different incentives in the IRA that can help steel companies build out their own green hydrogen infrastructure,” Lewis said. “Everything should be on the table. Steel companies would be such huge off-takers for green hydrogen, they can build their own economy here.”
At the BP Whiting oil refinery, 10 miles from Gary Works, there are plans underway for production of blue hydrogen, or hydrogen made with natural gas followed by capture and sequestration of the emissions. The plan is a marquee part of the Midwest (MachH2) hydrogen hub, one of seven planned hubs nationwide slated to receive $7 billion total in federal funding. Such blue hydrogen could be used to power a steel mill, with theoretically no resulting greenhouse gas or public health-harming emissions.
However, local environmental and public accountability leaders are strongly opposed to blue hydrogen production in the region, since carbon sequestration has not yet been done successfully on a large scale in the U.S., and it would entail pipelines carrying carbon dioxide from the refinery to a sequestration site.
“The carbon capture component makes us very nervous, it seems to me they’re rushing into this without really taking the time to study it more seriously,” said Northwest Indiana resident Connie Wachala, another graduate of the sustainable steel program. “That might be because of all the money DOE is making available to industry. I wish our elected and industry officials would start thinking more creatively about how to make [green hydrogen] happen, how to make things better for the people in the neighborhoods and around the steel mills as well as for the shareholders.”
A different future
All four of Wachala’s grandparents came from Poland to work in the steel mills.
“Growing up in the 1950s, I remember my mom hanging the laundry up in the yard on a clothes line. If the wind was blowing a certain way, you’d get black particles on the clothes,” remembered Wachala, who worked as a creative writing teacher before retiring. “My dad’s car was always covered with that soot.”
Booker’s mother worked as a crane operator at the now-closed Bethlehem Steel mill in Burns Harbor, Indiana — among the first wave of women of color to be hired.
“I was proud she worked in the mill and took care of us, but I did not want [that job] whatsoever, seeing her come home every night after the swing shift, with the big old boots and jacket,” said Booker. “I wanted to go to college. It was a source of contention with my mom and I for some years.”
That was in the days when locals largely believed, “if you want a good partner, you’ve got to get one that works in the mill,” she continued. “It was like a prestigious job and position. People looked up to people who worked in the mill.”
Now, Booker laments, “Gary is like a joke,” scorned for its economic decline since the steel industry automated and shrunk — hemorrhaging jobs, and for the pollution that is still emitted. If the merger with Nippon does not go through, it’s widely believed U.S. Steel would eventually close the mill, as it closed its South Works plant in Southeast Chicago decades ago. At their height, the South Works and Gary Works plants together employed about 40,000 people in the Chicago area.
Thomas wrote a frustrated rebuttal to the Chicago Tribune editorial board opining that the Nippon merger was crucial to Gary’s future. She and other local leaders say they don’t want the mill to close, but they can demand better than the extension of heavily polluting industry.
“It’s just perpetuation of this as a sacrifice zone,” said Thomas. “‘This is what you’ve always been, this is how we’re going to keep you.’ But that’s not going to fly anymore.”
The one thing Kamala Harris and Donald Trump seem to agree on is that the road to the White House runs through Pennsylvania, the nation’s most populous swing state.
October polls show an even split in the Keystone State, and its 19 Electoral College votes could well decide the election. Not a week went by in September without one or more visits from each campaign. And Pennsylvania is where Harris and Trump met face-to-face for their first and only debate, during which both candidates vied to convince Americans that they can deliver more prosperity. Harris wants to grow the economy in part by continuing the clean energy manufacturing policies enacted by the Biden administration; Trump wants to roll them back.
Given the immense electoral stakes, I decided to visit the state to see if the idea of a clean energy future is resonating with Pennsylvanians and how that transition is starting to materialize in a place where coal, oil, and gas have reigned supreme since the 1800s.
Pennsylvania’s coal abundance jump-started the transition away from burning wood as a primary energy source. Coal later made the state the steelmaking capital of America and powered the nation for decades. Meanwhile, oil production surged beginning in 1859, when Edwin Drake tapped the country’s first oil well at Titusville, and the state led U.S. oil production through the end of that century.
More recently, when engineers commercialized fracking in the 2000s, the Marcellus Shale, which stretches under Pennsylvania, quickly became the biggest shale-gas-producing region in the nation.
Now, though, Pennsylvania is at a crossroads: The resources that fueled Pennsylvania’s past growth are plateauing or petering out.
“Coal employment has gone off a cliff,” said Seth Blumsack, who runs the Center for Energy Law and Policy at Penn State. “You had an influx of natural gas jobs — that growth has largely leveled off, as Pennsylvania hit this kind of steady state of gas production.”
This isn’t the first time Pennsylvania’s core economic drivers have waned. Factories and steel mills took a beating in the 1970s and 1980s, as foreign producers competed in earnest with America’s industrial machine. Plants that sustained whole towns closed down, with nothing to replace them. The ironworks Andrew Carnegie built in 1875 still operates on the bank of the Monongahela River, but owner U.S. Steel is desperately trying to unload it to Japan’s Nippon Steel.
These conditions have created new opportunities for the clean energy transition to take hold. Political leaders like Democratic Gov. Josh Shapiro and business owners are embracing low-carbon industry as an economic development strategy for the energy-rich state.
Shapiro has pushed to strengthen the state’s outdated clean energy standard for power production, and he signed a bill this summer to establish ground rules for developing carbon-sequestration projects. His administration recently won $400 million in federal funding from the U.S. Environmental Protection Agency (“the second-largest federal grant in Pennsylvania’s history,” a spokesperson for the governor pointed out). Pennsylvania will disburse that money in competitive grants to industrial entities proportional to their ambitions at carbon reduction; the Shapiro administration wants the ensuing projects to slash statewide industrial emissions 10 percent by 2050.
Given the state’s long history of oil and gas, hydrogen production is sure to loom large. In the lower-carbon future, clean hydrogen could become the next key energy commodity. Last year, Biden’s Department of Energy awarded seven proposed hydrogen hubs around the country roughly $1 billion each. Pennsylvania, as Shapiro regularly points out, was the only state to win funding for two: The Philadelphia-based hub is slated to produce hydrogen with nuclear power and renewables, while the Pittsburgh-based hub will focus on turning fossil gas into hydrogen and stowing the ensuing emissions underground.
But Pennsylvania’s industrial decarbonization is just getting started.
“You’re not seeing the finished product, but so many things are falling into place,” said John Carlson, who oversees state policy engagement in the region for Clean Air Task Force, a climate-solutions think tank.
Clean energy manufacturing, though, is already beginning to put Pennsylvanians to work. A few entrepreneurs have retooled historic Pittsburgh-area factories to turn iron and zinc into batteries that store power from the sun and wind. Steelworkers forge the backbone that holds phalanxes of solar panels, bolstering America’s fastest-growing source of electricity.
Pennsylvania has fallen behind other states in building clean power plants, but renewables developers are getting more ambitious. In Clearfield County, northeast of Pittsburgh, developer Swift Current Energy is building the biggest solar plant in the commonwealth on 2,700 acres of reclaimed mine land.
“There’s this huge industrial knowledge base in Pennsylvania,” Blumsack said, “and people who want to work, and so how do you harness that?”
From coal and gas to hydrogen
The Marcellus Shale arcs from southwest to northeast Pennsylvania, undergirding the state physically and economically.
Other states talk of phasing out fossil fuel extraction to tackle their planet-warming emissions. In Pennsylvania, Shapiro, working with split control of the legislature in Harrisburg, speaks pragmatically of harnessing the state’s mineral wealth for the goal of decarbonization. In her Pennsylvania debate appearance, Vice President Harris renounced her earlier opposition to fracking: “Let’s talk about fracking, because we’re here in Pennsylvania. I made that very clear in 2020. I will not ban fracking.” Such is the gravitational pull of the Marcellus.
But talking about pumping fossil fuels while decarbonizing is much easier than doing it. So I ventured through the corduroy-like ridges of the Appalachian foothills to a place where people are working to make it happen: Penn State, formed as an agricultural school in 1855 and now home to nearly 50,000 students in a bucolic town aptly named State College.
Sanjay Srinivasan greeted me outside the beige concrete structure that houses the Energy Institute, where the College of Earth and Mineral Sciences conducts research to unlock lower-carbon opportunities for the state.
I did a double take as we approached the building — the sign on the exterior wall said “Coal Utilization Laboratory,” a relic of the not-so-distant past. In the lobby, we passed displays of actual coal in all its dark glory: an uninterrupted column of bituminous stretching to the ceiling, a pyramidal sampler of anthracite designated by colloquial gradations like Egg, Chestnut, Pea, and the fine little pebbles of No. 3 Buckwheat.
“We are interested in doing anything that we can to help communities in the Pennsylvania Appalachian region transition to the new energy economy,” Srinivasan told me.
Penn State’s Coal Utilization Laboratory has transformed into a research hub for ways to repurpose the state’s fossil fuel resources into lower-carbon energy. (Julian Spector/Canary Media)
The institute approaches that task by looking for existing energy infrastructure it can repurpose. That means researching ways to extract critical minerals from the region’s mining waste ponds and fly ash piles, or tap hot briny water in abandoned mines as a heat source for buildings. And, thanks to the billion-dollar hub grant from the DOE, western Pennsylvania could turn its fossil fuels into hydrogen to clean up heavy vehicles and industry.
“In this part of the world, the formations can be used for storing hydrogen. But better still, can we use the shale gas for producing hydrogen and then develop a closed-loop process where you don’t emit anything into the atmosphere?” Srinivasan posited.
Almost all hydrogen made today comes from blasting methane with steam at high pressure, which yields hydrogen gas and carbon dioxide. The machines that do this, called steam methane reformers, historically just vent the CO2 into the atmosphere. U.S. hydrogen production is highly concentrated in the Gulf Coast petrochemical corridor, where refineries use the gas in their production process.
The Appalachian hub is planning to fund efforts, like the KeyState project in Clinton County, to make hydrogen this old-fashioned way but then inject the CO2 stream underground for geological storage. The DOE concluded negotiations with this hub in July, kicking off the active planning phase, which could last for three years.
The Gulf Coast has successfully sequestered carbon that oil companies pumped underground to push out more oil. In Pennsylvania, operators and researchers have yet to prove this is commercially feasible. The plan, Srinivasan told me, is to drill down 8,000 to 10,000 feet, through the Marcellus Shale, through the Geneseo Shale, to the Oriskany Sandstone. The shale formations above would act as a cap on the carbon dioxide. The National Science Foundation recently funded Penn State to study the Appalachian Basin’s carbon-sequestration potential.
Many climate advocates doubt that hydrogen production from fossil fuels will ever be particularly clean. That said, hydrogen producers elsewhere have proved that they can achieve high rates of carbon capture at steam methane reformers, noted Sam Bailey, industrial decarbonization manager at Clean Air Task Force. Pennsylvania operators would also need to secure low-carbon electricity to run their operations, and buy methane from a supply chain that isn’t leaky.
“Some producers in the region have some of the lowest leak rates, but those obviously have to be verifiable and transparent,” Bailey said.
The mid-Atlantic hydrogen hub, centered around Philadelphia, would focus on electrolysis powered by offshore wind and nuclear power. The Shapiro administration expects both hubs to create 41,000 jobs, though the DOE estimates the hubs will take eight to 12 years to fully materialize.
There might be other pathways for turning fossil gas into clean hydrogen. Down the hallway, Srinivasan’s colleague showed me a tabletop device that performs what’s called thermocatalytic decomposition: The machine essentially cooks methane at low temperatures until it lets out pure hydrogen and inert, solid carbon. That would be much simpler than catching and injecting gaseous carbon deep underground.
This machine at Penn State breaks down methane under low heat to yield hydrogen and solid carbons. If the emerging technology gains traction, it could process gas leaking out of old mines. (Julian Spector/Canary Media)
The tabletop version I saw is still “frontier technology,” Srinivasan cautioned, made possible by recent advances in catalyst efficiency. But it could be a good fit for smaller installations to catch methane leaking out of Pennsylvania’s many abandoned coal mines. Modular decomposers could convert those decentralized streams of intensely planet-warming gas into harmless carbon solids that can be used as industrial feedstocks.
Pittsburgh steel goes solar
The town of Leetsdale hugs the Ohio River north of Pittsburgh, surrounded by sprawling industrial complexes and freight lines. During World War II, Bethlehem Steel fashioned barges and landing craft there. Historians describe that war as a clash of steel that the U.S. won because its factories cranked out more tanks, planes, and ships than its opponents.
Most of those factories are long gone, but JM Steel, an affiliate of the century-old company Jennmar, took over a site in Leetsdale one year ago and reopened it with a new mission: bending steel to the will of the burgeoning solar industry. Its preliminary success shows how federal clean energy policy is breathing new life into Pennsylvania’s legacy industries — exactly what the hydrogen hubs are supposed to do.
When I rolled up to the riverside lot, the factory looked like it was fortified for some kind of invasion. Thirty-foot steel tubes had been trussed up by the dozen and stacked to form an impenetrable barricade taller than a person.
Pittsburgh native Chris Bartley led me through the steely labyrinth, explaining that these pipes were torque tubes ready to ship. His employer, Nextracker, uses the tubes to mount huge numbers of solar panels that can change their angle throughout the day.
Early in the solar revolution, developers installed panels in fixed positions, at what seemed like the most advantageous angle. Silicon Valley startup Nextracker revolutionized the market by attaching panels to trackers that follow the sun’s arc, and pivot away from dangers like hail or high wind. This innovation enhanced solar power output and made Nextracker one of cleantech’s clearest commercial successes: It went public in 2023 and now trades with a market cap over $5 billion. To supply its booming business, Nextracker enlists specialists like JM Steel to sculpt metal to its specifications.
Chris Bartley stands before stacks of Pittsburgh-made torque tubes, which his company Nextracker sells to large-scale solar projects so the panels can track the sun. (Julian Spector/Canary Media)
In a little meeting room off the factory floor, Negley Rodgers, who oversees plant operations for family-owned JM Steel, told me the plant ships an average of six truckloads of torque tubes per day — 350,000 torque tubes since last October. They go straight to solar plants in the region, where the tons of steel translate to megawatts of cheap, clean power rushing onto the grid.
We donned hard hats, earplugs, and orange scratch-resistant sleeves for my exposed forearms, then walked into the cavernous factory. First we saw the “master coils” of rolled-up flat steel that the company buys from domestic producers like Nucor and SDI. The coils don’t look overwhelmingly large, but are so heavy that flatbed trucks can carry only one at a time, Rodgers noted. The high-ceilinged factory has a built-in crane capable of lifting 40 tons to maneuver the coils into position.
Workers feed these coils into machines that use heat and immense force to roll the flat material into thick round pipes. Another station drills the holes that will attach the solar panels. JM adjusts the drilling arrangement for each project — some use bigger panels, some smaller, but the company can accommodate them all on the same production line.
Before Covid-19, Nextracker relied on a more typical globalized supply chain. Then CEO Dan Shugar decided to localize tracker production to where his customers operated around the world: Solar plants would get trackers made nearby, so nothing got stuck in port overseas. A couple of years later, the IRA sweetened the deal with meaningful financial incentives to produce solar-power components domestically.
The Inflation Reduction Act created an 87-cent-per-kilogram tax credit for torque tube manufacturing. Additionally, solar developers can access an extra 10 percent tax credit for their power plants by hitting a critical mass of domestic components, per an IRS rubric. Trackers include torque tubes, rails, controllers, and motors, Bartley explained; sourcing all those components in the U.S. unlocks a bonus, which nets 24.7 percent coverage for the overall solar project.
JM Steel uses heat and force to turn coils of flat, rolled steel into torque tubes capable of holding up solar panels in inclement weather. (Julian Spector/Canary Media)
The exact level of domestic content varies by project, based on what a developer is looking for. A U.S.-made tracker creates flexibility for how the company sources other components while still meeting the IRS cutoff.
Conventional corporate wisdom long held that offshoring production to China cut costs and improved profits. Sourcing a 100 percent domestic tracker still adds a premium, Bartley said, but it’s already possible to make most of the system here without driving up cost.
“Looking at our cost of a tracker fully delivered to a job site, we’re seeing really competitive costs and pricing [while] making a significant part of the tracker domestically,” he said. “As time goes on, we’re expecting any sort of premium like that to go down, because we’re expanding capacity of these other components, like our electronic components.”
Part of that favorable comparison to foreign imports has to do with the inescapable heft of this product: “They’re not shipping nuts and bolts that they can pack into a tight box on a ship,” said Rodgers. “They’re shipping these large, 30-foot-long, five-inch diameter tubes that take up a massive amount of volume on a ship.”
Steel companies have opened 20 factory sites across the U.S. that exclusively produce torque tubes for Nextracker; the factories wouldn’t exist without the demand from the booming solar market. JM ships from Pittsburgh to places like Indiana, Illinois, and Tennessee, but business in Pennsylvania has been picking up, as evidenced by the blockbuster Mineral Basin Solar project. That one will put 400 megawatts on reclaimed mining land northeast of Pittsburgh. The power and its clean energy credits will actually flow to New York, but millions of dollars of lease payments and tax revenues will stay in the county.
For JM Steel, the imperative to decarbonize has given new urgency to the skills and products that Pittsburgh long excelled at. At the same time, U.S. Steel is trying to unload its flagship Pittsburgh steel plant to a Japanese company, arguing that it’s the only way to remain commercially viable. I asked Rodgers if that deal signaled the end of an era for American steelmakers.
“I can’t comment on that,” he said, referring to U.S. Steel’s position. “Just — manufacturing is still viable, and it’s still happening in the United States.”
Indeed, the growing pressure on big steel buyers to source lower-carbon or “green” steel could give U.S. companies an edge on overseas competition. The U.S. already uses a high proportion of electric arc furnaces to melt scrap metal into new products; those can run on clean electricity to further curb their carbon footprint. The industry is also exploring ways to decarbonize the carbon-intensive conversion of iron ores to metallic iron, by using clean hydrogen instead of coal. Pennsylvania doesn’t have any of those facilities operating yet — the world’s first large-scale commercial plant of this kind is under construction in Sweden. But the hubs aim to bring clean hydrogen supply to greater Pittsburgh, and the DOE has funded steel companies to build initial facilities to use it.
For now, JM Steel’s plant serves Nextracker’s needs with some 53 employees — a welcome addition, but not close to the scale of employment at the site in bygone decades. For clean energy buyers or green steel customers to make a mark on the regional economy, they’ll need to put many more people to work.
Reopening factories for battery breakthroughs
Solar panels planted on Pittsburgh steel clean up the grid during sunny hours. But as solar generation provides ever more electricity, new energy storage technologies will be needed to turn cheap renewables into round-the-clock power.
Federal policymakers hope to bring battery manufacturing back to the U.S. after China pulled far ahead in its capacity to make lithium-ion batteries. It’s extremely difficult to catch up to competitors who are already producing at tremendous scale — the recent financial struggles at Europe’s Northvolt attest to that. Pittsburgh, though, has become a hub for fabricating novel battery technologies that aren’t made anywhere else in the world, a risky strategy with the potential for a big payoff.
Habitually cash-strapped startup Eos makes zinc-based batteries at the junction of Turtle Creek and the Monongahela. For decades, Westinghouse built electrical generators on the site that powered the Hoover Dam and other icons of modern America. Nikola Tesla once toiled there, as did more than 20,000 workers in the plant’s heyday. But Westinghouse shuttered the Turtle Creek plant in 1988, gutting the economy of the surrounding Mon Valley.
Now Eos employs 300 people to manufacture energy storage in 150,000 square feet of the old Westinghouse complex. If the unconventional product takes off, Eos could expand and further boost the local economy — but that’s a big if.
The Westinghouse facility in Turtle Creek used to employ 20,000 people to make electrical generating equipment. It closed in the 1980s, but has recently opened up to growing businesses like Eos. (Julian Spector/Canary Media)
Eos has toiled, since 2008, to commercialize a new type of battery that could beat lithium-ion on fire safety and cost for longer-duration energy storage. Lithium-ion batteries almost always win customers looking to deliver stored power for four hours, and increasingly five or six. Beyond that, lithium-ion gets prohibitively expensive. Eos markets its batteries as capable of delivering power for three to 12 hours, which runs the gamut from the incumbent technology’s sweet spot to a storage duration that few customers have ever purchased.
That’s a tough market to break into, and Eos survived its first decade with little commercial traction to show for it. In 2019, the board brought in a new management team, a crew of GE veterans, led by CEO Joe Mastrangelo. He stopped outsourcing fabrication to contractors in China and localized production in Pittsburgh.
I met Mastrangelo in a conference room above the factory. He wore thick-framed glasses and a company hoodie, lime-green logo on forest green. The outfit reminded me of Pennsylvania Sen. John Fetterman (D), who famously bucked tradition and wore hoodies in the halls of power. Mastrangelo pointed out that Fetterman lived a mile down the street in Braddock, where he used to be mayor, in a house overlooking the U.S. Steel plant.
Reshoring the supply chain surely saved Eos during Covid-19, Mastrangelo explained. If production had frozen for a couple of years when China closed its factories, “we would have been done.” Eos also avoided under-discussed costs of offshoring, like lengthy, expensive flights to China to check on manufacturing progress. Eos built the factory with its own money — a rare feat in the incentive-happy cleantech factory boom — but found itself ready to capitalize on the domestic manufacturing incentives created by the 2022 Inflation Reduction Act.
Downstairs, I saw the fully automated line that Eos installed in June, capable of producing 1.2 gigawatt-hours per year. The machinery sat inside a wire-fenced perimeter. A succession of robots picked up gray plastic boxes, stocked them with Eos’ proprietary electrodes, then injected them with a liquid electrolyte in two carefully calibrated gushes, to prevent it from foaming and spilling.
Eos installed a fully automated line this summer to mass-produce its unusual zinc batteries. Inside the perimeter, only machines operate — unless they need a little human assistance. (Julian Spector/Canary Media)
Eos employees patrolled the perimeter, many of them wearing the same green-on-green hoodie as their CEO. Their job was to keep the machines running: When a robot got confused, or the operating controls hit a glitch, alarms sounded and the technicians hurried over. This happened throughout my tour; as I’d seen in other cleantech factories, “full automation” is more aspirational than descriptive.
The bustling factory embodies the theory that Pennsylvania’s abandoned factories can spring to life to serve the material needs of the clean energy revolution. Pennsylvania’s minimum wage is $7.25 an hour, but Eos’ average wage is above $20, Mastrangelo said. Employees get a 3 percent direct contribution to their 401(k), and regular grants of company stock (Eos went public in 2020 via a special-purpose acquisition company). “We also view this as a massive opportunity for everybody to get wealth creation,” Mastrangelo said.
But startups are unsteady vessels for economic growth, and Eos’ finances are more unstable than most.
Last year, Eos spent $169 million to make $16.4 million in revenue. It’s normal for a startup to lose money while ramping up commercial production. But Eos’ public listing failed to net enough money to fully fund the buildout, so it has repeatedly beseeched investors for more infusions (like $100 million from Koch in 2021). This summer, Nasdaq nearly booted Eos for trading below $1 a share for too long.
Mastrangelo escaped that ignominy by closing a $325 million commitment from a domestic supply chain–focused fund at private equity firm Cerberus, on June 24, in the form of a loan with stock warrants (and surely one or two strings attached). Since then, Eos’ share price soared all the way past $3.
With this private-equity lifeline in hand, Mastrangelo has faith that demand for his unusual batteries will pick up. Eos is commissioning a 35-megawatt-hour storage system serving a microgrid on a Native American reservation in Northern California, funded by a California Energy Commission grant for long-duration storage. That customer already signed up for an expansion to 60 megawatt-hours. Eos also delivered a 10-megawatt/4-megawatt-hour standalone system in Texas for Pittsburgh-based developer IEP. These are small potatoes compared with lithium-ion battery projects, but substantial for the ragtag category of erstwhile lithium alternatives.
Once the gray, boxy battery cells are produced, workers install them in containers to ship to customers. (Julian Spector/Canary Media)
“The one thing we’ve always told everybody is, the market needs a product like ours,” Mastrangelo said. “We continue to do things that haven’t been done before, and we just have to keep executing on our plan, and eventually the market will reward performance.”
An even more unusual battery is being fabricated about 36 miles west of downtown Pittsburgh. This one, designed by Form Energy, uses iron as a cheap storage material and promises to deliver clean power for up to 100 hours, far beyond what lithium-ion batteries can handle affordably. Unlike Eos, Form had no trouble lining up venture capital investment and hundreds of millions of state and federal dollars to fund its buildout; in fact, the company just closed another $405 million equity investment on October 9.
Form took barely a year to transform the slag-studded field of an abandoned steel mill into a gleaming new factory. Its white outer wall rises like a curtain to reveal a transparent entranceway, highlighted in the company’s trademark orange. Inside, an airy vestibule lined with greenery and an exhibit on the town’s industrial history gives way to the 550,000-square-foot production zone.
“We wanted it to be an inviting place,” CEO Mateo Jaramillo told me from a glass room on the mezzanine level, suspended above the factory floor. “It should feel like innovation. It should feel like something new. It should feel like a safe, clean place to work.”
Form developed its technology at labs near Berkeley and MIT, then expanded to a facility in the tiny town of Eighty Four, outside Pittsburgh. The company doubled down on the region for its full-fledged factory, and landed several hundred million dollars in state incentives from West Virginia to locate in that state, in the former steel town of Weirton. Pittsburgh is the closest big city to Weirton, and many of the workers commute from Pennsylvania. The success of this factory, like JM Steel or Eos, speaks to Appalachia’s ability to seize the clean energy era for its economic revival.
Form CEO and co-founder Mateo Jaramillo inspects a finished iron-air battery cell at his company’s newly built factory west of Pittsburgh. (Julian Spector/Canary Media)
Form chose a factory site rich in symbolic resonance: The startup is claiming a spot in the industrial landscape of the Ohio River Valley, creating jobs where the legacy industries seem capable only of shedding them (steel giant Cleveland-Cliffs was clinging on next door, but idled that operation in April; the company hopes to reopen the site to make electrical transformers starting in 2026). Form even uses iron, the same material that, with coal, fueled the region’s steel boom.
These layers of narrative meaning play swimmingly at ribbon cuttings, but I was curious what they offer once the tax incentives are secured. Jaramillo acknowledged that “grand poetry” isn’t what makes batteries.
“On the day-to-day, we don’t think a lot about the precise industrial legacy — we’ve got a job to do, so we go do the job,” Jaramillo said. “That’s probably the most direct legacy, is people who are really oriented on taking care of the job.”
Form has seen “huge demand” for open positions, and Jaramillo reported no problems finding the quality and number of workers needed. The company promised the state of West Virginia that salaries will average at least $63,000 per year — well above minimum wage, and substantial in a region with low costs of living.
So far, Form runs a single shift per day, for 10 or 12 hours. Some 300 people work at the factory, but that should grow to 750 in a few years, Jaramillo said. The plan is to quintuple capacity from 2025 to 2026, and quadruple it again from 2026 to 2027, at which point the factory will make 500 megawatts per year; for the long-duration format, that translates to 50,000 megawatt-hours.
The Pittsburgh metro area scores quite high for its capability to manufacture a range of clean energy technologies, per economic development analysis by climate think tank RMI.
Eos and Form were the first major battery makers to turn that potential into real jobs. Neither technology has been deployed on the grid in sufficient scale to ensure its longevity as a climate solution; that work lies ahead of them. But they demonstrate that it’s possible for the decarbonization mission to reanimate long-abandoned factories and put Pennsylvania’s workers back on the line.
Over two centuries, Pennsylvania’s energy resources brought clear gains in jobs and wealth. The nascent industrial decarbonization transition needs many more years of dedicated federal and local support before it can credibly substitute for the legacy energy economy. That’s not a convenient timetable for Democrats trying to make the case now for a Harris administration, and yet the outcome of the election will have an enormous impact on whether that support continues.
Residents with heat pumps in four Massachusetts towns will soon pay hundreds of dollars less for their electricity over the winter, thanks to a new pricing approach advocates hope will become a model for utilities across the state.
State regulators in June approved a plan by utility Unitil to lower the distribution portion of the electric rate from November to April for customers who use heat pumps, the first time this pricing structure will be used in the state. It’s a shift the company hopes will make it more financially feasible for residents of its service area to choose the higher-efficiency, lower-emissions heat source.
“We asked, is there a way we can structure the rates that would be fair and help customers adopt a heat pump?” said Unitil spokesman Alec O‘Meara. “We recognize that energy affordability is very important to our customers.”
A balancing act
Electric heat pumps are a major part of Massachusetts’ strategy for reaching its goal of going carbon-neutral by 2050. Today, nearly 80% of homes in the state use natural gas, oil, or another fossil fuel for space heating. Looking to upend that ratio, the state has set a target of having heat pumps in 500,000 homes by 2030.
One of the major obstacles to this goal is cost. To address part of this barrier, Massachusetts offers rebates of up to $16,000 for income-qualified homeowners and $10,000 for higher-income residents for heat pump equipment.
The cost of powering these systems though, can be its own problem. Natural gas prices have been trending precipitously downward for the past two years and Massachusetts has long had some of the highest electricity prices in the country. This disparity can be particularly stark in the winter, when consumers using natural gas for heating get priority, requiring the grid to lean more heavily on dirtier, more expensive oil- and coal-fueled power plants, said Kyle Murray, Massachusetts program director for climate and energy nonprofit Acadia Center.
So switching from natural gas to an electric heat source — even a more efficient one like a heat pump — doesn’t always mean savings for a consumer, especially those with lower incomes.
“Electric rates are disproportionately higher than gas rates in the region,” Murray said.
Unitil’s new winter pricing structure is an attempt to rebalance that equation. In New England, electric load on the grid is generally much lower in the winter, when people turn off their air conditioners and switch over to gas or oil heating. That means that the grid, built to accommodate summer’s peak demand, has plenty of capacity for the added load of new heat pumps coming online — no new infrastructure needs to be built to handle this demand (for now, at least).
“The marginal cost of adding demand is lower,” said Mark Kresowik, senior policy director at American Council for an Energy-Efficient Economy, which supports heat pump-specific rates.
Unitil, which provides electricity to 108,500 households, decided to let customers share in that lower marginal cost. The company estimates customers will save about six cents per kilowatt-hour, which would work out to a monthly savings of more than $100 for a home using about 2,000 kilowatt-hours per month. The new rate should go into effect in early 2025, O’Meara said.
Statewide solutions?
As Unitil is preparing to deploy its heat pump rate, environmental advocates and other stakeholders are pushing for adoption of this strategy beyond Unitil’s relatively limited territory.
Public utilities regulators are in the middle of considering a rate case filed by National Grid, which serves some 1.3 million customers in Massachusetts. National Grid has proposed what it calls a technology-neutral “electrification rate,” which would provide discounts to certain high-volume energy users, which would include heat pump users.
However, several advocates for low-income households and clean energy — including Acadia Center, Conservation Law Foundation, Environmental Defense Fund, Low-Income Energy Affordability Network — as well as the state energy department and Attorney General Andrea Campbell argue that this approach is inadequate. They’ve submitted comments urging regulators to require National Grid to offer a heat pump rate similar to Unitil’s plan, but modified to work within National Grid’s pricing model.
“Every intervenor in the docket who commented on the electrification proposal in any capacity was negative on it,” Murray said. “And the [department of public utilities] in its questioning seemed fairly skeptical as well.”
National Grid declined to comment on the pending rate case.
The electrification rate, opponents argue, would lower costs not just for households with heat pumps, but also for those with inefficient electric resistance heating and even heated pools, effectively running counter to the goal of reducing greenhouse gas emissions.
“The ‘electrification’ proposal would apply to all electricity consumption, whether or not consistent with the Commonwealth’s climate policy of reducing greenhouse gases,” said Jerrold Oppenheim, a lawyer for the Low-Income Weatherization and Fuel Assistance Program Network and the Low-Income Energy Affordability Network.
It would also do nothing to encourage heat pump adoption among low- and moderate-income households, they say: Some 48% of low-income customers interested in switching to a heat pump would actually see bill increases of up to 33%, according to a brief filed by Oppenheim for the network.
Beyond the National Grid rate case, other stakeholders are also pushing for seasonal heat pump rates. The state has convened an Interagency Rates Working Group to study and make recommendations on the challenges of changing how electric rates are designed to encourage electrification of home heating and adoption of electric vehicles. In August the group released an analysis that found seasonal rates created significant savings for homes with heat pumps.
“They came to the same conclusion, that this is the right approach,” Kresowik said.
Eventually, the introduction of advanced metering technology will simplify the process of applying lower rates to desired uses, like heat pumps and electric vehicles. But the full deployment of these systems is still several years in the future, and action to ease adoption of heat pumps must be taken much sooner, advocates argue.
In the meantime, many have expressed some optimism that regulators will require National Grid to make its electrification proposal more responsive to the state’s climate and equity priorities.
“I would be surprised if the electrification pricing proposal exists as is in the final [regulatory] order,” Murray said.
The driest summer in more than a decade prompted an Ohio watershed district this summer to take the unprecedented step of limiting the use of water for oil and gas fracking.
The restrictions applied only to Atwood Lake, a popular boating and fishing spot southeast of Canton that has experienced a foot and a half drop in water levels over the past few months of drought.
It’s a scenario some environmentalists anticipated years ago, saying that climate change will require state and local officials to more carefully regulate the use of water for oil and gas extraction.
“They’re not being proactive enough,” said Leatra Harper, director of the FreshWater Accountability Project, stressing that the lakes are public resources. “The obvious issue is there aren’t adequate protections.”
Hydraulic fracturing, as it’s more formally known, pumps millions of gallons of water mixed with sand and chemicals down into oil and gas wells. The process causes cracks in petroleum-bearing rock, and sand in the fluid props the cracks open. Oil and gas flows from the fractures into the well and up to the surface.
The process uses millions of gallons of water for each horizontally drilled well, and well pads built within the last 12 years often have six wells. The water can be recovered and recycled to some extent. Eventually, though, the water must be disposed of in underground injection wells. That step permanently removes it from the water cycle.
The Muskingum Watershed Conservancy District manages ten lakes and four dry dams in southeastern Ohio for purposes of flood control, recreation and conservation. One of its biggest customers for water sales is the oil and gas industry.
“We’re not in a crisis situation by any stretch of the imagination, but this was just our balancing act to make sure we protect, as much as we can, all of our missions,” said Craig Butler, chief executive of the district. He estimated less than one inch of Atwood Lake’s decline can be attributed to oil- and gas-related withdrawals.
On August 28, the district curtailed water withdrawals by 75% from Atwood Lake. The following week, it curtailed withdrawals from the lake completely.
Lots of water
Under Ohio law, oil and gas drilling operations are generally allowed to withdraw from state waters an average of up to 2 million gallons per day in any 30-day period. Sixty million gallons would fill nearly 91 Olympic-sized swimming pools.
While the total number of gallons sold is huge, it’s relatively small compared to the billions of gallons in the district’s lakes. Butler compared it to two or three sheets in a notebook.
“We’re really comfortable when we say it’s a negligible impact based on the size of our reservoirs,” Butler said.
Oil and gas companies pay a price for the water — around $3 per 1,000 gallons, according to Ted Auch, Midwest program director for FracTracker. He and other critics think the price should be higher.
“We charge as much as we can,” Butler answered, but if the district’s price gets too high, oil and gas companies can “stick their straw in” elsewhere, such as where a stream crosses private property. Then they may be able to suck out even more without a formal agreement with the watershed organization.
And because some of those sources flow into the district’s lakes, the effect on the district’s water resources would be largely the same, without the district getting revenue from the sales. Some of the funds from the oil and gas industry have paid for efforts to improve water quality and minimize flooding to improve the area’s resilience to climate change, Butler added.
The situation reflects a shortcoming in state law, said Melinda Zemper, a spokesperson for Save Ohio Parks.
“It is clear our state legislators ignore the depletion and contamination of our precious fresh drinking water used in the fracking process,” she said. “And there will always be another landowner who wants oil and gas revenue from leasing mineral rights or selling water flowing through his or her property.”
Operators recycle a lot of the water that’s withdrawn, and the fracking process has gotten more efficient over the years, said Mike Chadsey, a spokesperson for the Ohio Oil and Gas Association.
Getting hard data on recycling is difficult, however. FracFocus, a data clearinghouse, has some data on the composition of fracking fluids, but reporting is voluntary.
According to the Ohio Department of Natural Resources, oil and gas ranks seventh out of its eight registered water use categories. The agency’s 2022 water withdrawals map shows those other categories include public water supplies, agriculture, utilities and other classifications.
Total water withdrawals for the oil and gas industry that year were about 5.17 billion gallons, according to data provided by Karina Cheung, an ODNR spokesperson. A 2024 U.S. Geological Survey report said peak withdrawals reached approximately 5.75 billion gallons in 2017.
Looking ahead
Questions about future water use for fracking will remain after the current drought ends — possibly soon from the remnants of Hurricane Helene.
The Muskingum Watershed Conservancy District does a careful review of any company’s request for water withdrawals before a contract is signed, Butler said. Contracts also say water withdrawals can be curtailed if the district deems it necessary, as it did at Atwood Lake, he added.
Critics like Auch contend various data gaps should be filled to ensure more complete reporting. They also want any pre-withdrawal reviews to be more conservative and forward-looking.
Consideration of potential impacts should focus more on possible water-deficit years like this one, Auch said. Otherwise, “you are rapidly altering the savings bank of your watershed by depleting the resource that it has to carry over from year to year.”
Planning also should cover a longer time horizon, said Julie Weatherington-Rice, a hydrogeologist with Bennett and Williams Environmental Consultants in Columbus. Ohio might generally expect warmer, wetter and wilder weather as climate change continues.
Among other things, Ohio is seeing some intense storms, as well as periods of heavy rainfall. Those heavy rains might bump up the total yearly precipitation, but they don’t soak into the ground the way milder, more sustained rains do, Weatherington-Rice said. That could affect groundwater supplies for local areas, causing them to look for backup supplies, she said. And droughts can still occur, as this year shows.
Water planning also should account for likely migration into Ohio as climate change has more severe impacts elsewhere, Auch said. “We need to start looking at water resources out 10, 15, 30 years.”
CORRECTION: An earlier version of this story misstated the amount gas companies pay for water. It is around $3 per 1,000 gallons of water, not $3 per gallon.
The U.S. Department of Agriculture announced in September it will distribute $7.3 billion in grants and loans for rural clean energy projects serving 23 states. (Photo courtesy of the National Center for Appropriate Technology and the Agrisolar Clearinghouse | USDA)
Pennsylvania wants to remain a manufacturing powerhouse. But state leaders also want to reduce climate change-causing emissions from steel mills and other industrial facilities, while cutting back the toxic pollutants that cause health problems in nearby neighborhoods.
Thanks to a nearly $400 million investment from the federal government, the state is preparing a massive plan to help industrial operators upgrade to new technologies and switch to cleaner fuel sources.
“Pennsylvania was one of the birthplaces of the industrial revolution, and now we’ve been given the opportunity to lead the nation in the industrial decarbonization movement,” said Louie Krak, who is coordinating the plan for the state Department of Environmental Protection.
Leaders in every state in the country have their own big plans. North Carolina and neighboring states are preparing to restore wetlands and conserve natural areas along the Atlantic coast. Iowa leaders intend to plant trees in neighborhoods that lack shade. Local governments in Texas plan to help residents install solar panels on their rooftops. And Utah is readying to purchase electric buses and reduce methane emissions at oil and gas operations.
All of these plans are backed by federal money from the Inflation Reduction Act, the climate law passed by Congress in 2022. But former President Donald Trump, who has called climate change measures a “scam” and vowed to rescind “unspent” funds under the law, could throw much of that work into chaos if he retakes the White House.
Legal experts say Trump couldn’t outright cancel the law without an act of Congress. But climate leaders say a Trump administration could create extra barriers for grant awards, slow the approval of tax credits and delay loan requests. If the federal support becomes unreliable, projects could lose financing from the private sector and cease to be viable.
“Even if the money is technically safe, we would definitely expect to see agencies [in a Trump administration] dragging their feet,” said Rachel Jacobson, lead researcher of state climate policy at the Center on Budget and Policy Priorities, a progressive think tank.
Federal agencies have already announced plans to award $63 billion — mostly in the form of grants — to states, nonprofits and other entities for a host of projects to fight climate change, according to Atlas Public Policy, a climate-focused research group. Many Republican-led states have, for the first time, drafted plans to fight climate change in order to compete for the money.
In addition, the feds are rolling out billions more in loans and tax credits aimed at similar projects. States say the mix of funding sources and financial incentives that will soon be available could supercharge efforts to fight climate change and create green jobs.
Many states whose projects have been approved say they’re urging the feds to issue their funding before the election.
“There’s a risk that an incoming administration could cancel our agreement,” said Krak, adding that Pennsylvania is hoping to finalize its funding award this fall.
Another $30 billion from the law is still up for grabs, much of it aimed at reducing emissions in the agricultural sector. And agencies have just begun offering loans and tax credits to provide hundreds of billions more in financing.
“So many states have climate plans for the first time [because of the federal law],” said Ava Gallo, climate and energy program manager with the National Caucus of Environmental Legislators, a collaborative forum for state lawmakers. “Even states that weren’t supportive of the Inflation Reduction Act are certainly touting these projects.”
State plans
In July, Utah learned that it would be receiving nearly $75 million to carry out its climate plan. The program will pay for electric school and transit buses, help residents purchase electric vehicles and install equipment to reduce methane emissions at oil and gas operations, among many other components.
By 2050, the investments are expected to reduce carbon dioxide emissions by 1.4 million metric tons, said Glade Sowards, who is coordinating the plan for the Utah Department of Environmental Quality. Sowards said the plan was also designed to reduce pollution that harms public health.
Even states that weren’t supportive of the Inflation Reduction Act are certainly touting these projects.
– Ava Gallo, climate and energy program manager with the National Caucus of Environmental Legislators
North Carolina is focused on protecting natural areas. The state filed a joint plan with Maryland, South Carolina and Virginia that is set to receive $421 million in federal funding. The coalition plans to conserve and restore more than 200,000 acres in coastal areas in the four states. While the natural lands are valuable for pulling carbon from the air, the funding will also help to expand state parks and protect residents from flooding.
Like many of the state projects supported through the climate law, the four-state plan has been announced as a recipient but the funding agreement is still being finalized. State leaders are urging the feds to complete that this fall.
“We want to get this done quickly for two reasons: one, so we can get the work underway, but two, to make sure that the money will be there [before a new administration could threaten it],” said Reid Wilson, secretary of the North Carolina Department of Natural and Cultural Resources.
The federal law also will pay for trees in urban areas, where they can reduce the dangerous “heat island” effect and limit stormwater runoff and air pollution. Iowa earned a pair of grants totaling more than $5 million to increase tree canopy in its cities.
“We’ve never had this level of funding before,” said Emma Hanigan, urban forestry coordinator with the Iowa Department of Natural Resources. “We have a really low canopy cover, one of the lowest in the nation.”
Another nationwide program is set to offer funding in all 50 states to help residents put solar panels on their rooftops or buy into community solar operations. In Texas, a coalition of municipalities and nonprofits, led by Harris County (which includes Houston), earned a nearly $250 million award to carry out that work.
The program will largely focus on disadvantaged communities, with a requirement that solar projects reduce participants’ energy bills by at least 20%. Leaders in Texas expect the investment to reach about 28,000 households.
States are also tasked with distributing rebates to help residents with their home energy needs. Wisconsin was the first state to bring its rebate program online, with $149 million in funding. Residents can receive up to $10,000 to improve insulation, upgrade appliances or install electric heat pumps. Over time, they will see greater savings in the form of lower energy bills.
“It’s nice [for a contractor] to be able to sit at the kitchen table and say, ‘You’re getting $3,000 of work here, but the state is paying $2,800,’” said Joe Pater, director of the Office of Energy Innovation with the Public Service Commission of Wisconsin.
Three other states (Arizona, New Mexico and New York) have rebate programs up and running, and others are finalizing applications. Indiana is among the many states awaiting federal approval to launch its program. The state expects to offer $182 million in rebates starting in early 2025. Greg Cook, communications manager with the Indiana Office of Energy Development, said the state is hoping to execute its plan regardless of the election outcome.
The climate law also has boosted “green banks,” which are state or nonprofit-run institutions that finance climate-friendly projects. The nonprofit Coalition for Green Capital received $5 billion of the federal money, which it will use to build a network that includes a green bank in each state, said Reed Hundt, the group’s CEO.
Michigan Saves, a nonprofit bank, expects to receive $95 million as a sub-award from the coalition. Chanell Scott Contreras, the president and CEO of Michigan Saves, said the “unprecedented” funding will enable the bank to expand its work, which includes helping low-income residents weatherize their homes and financing electric vehicle chargers and solar installations.
Loans and tax credits
The grants given out to states and other entities are just the start. The climate law supersized a federal loan program for clean energy projects, bringing its lending authority to $400 billion. And a new mechanism known as elective pay will now allow states, cities and nonprofits to receive the clean energy tax credits that have long been available to the private sector.
Climate advocates say many of the plans that states are setting in motion rely on the financing and tax rebates — components of the law that are most vulnerable to political interference.
“If an administration wanted to completely thwart the ability of [the Department of Energy] to make those loans, they could do so,” said Annabelle Rosser, a policy analyst with Atlas Public Policy, which has been tracking the rollout of the climate law. “That could be cut off at the knees.”
Meanwhile, many states are relying on the new tax credit to support plans such as electrifying state vehicle fleets and installing solar panels on public schools. In Washington state, for instance, the Office of Financial Management is coordinating a governmentwide effort to ensure state agencies use elective pay to bolster their climate work.
But climate advocates fear that an Internal Revenue Service led by Trump appointees could stall that work.
“There’s a lot of concern about what [Trump] would do with IRS staffing to limit the ability for them to get the refund checks out,” said Jillian Blanchard, director of the climate change and environmental justice program with Lawyers for Good Government, a nonprofit focused on human rights. Such delays could “chill hundreds of thousands of projects,” she said.
“I’m not sure he knows that red states are counting on this money too.”
Stateline is part of States Newsroom, a nonprofit news network supported by grants and a coalition of donors as a 501c(3) public charity. Stateline maintains editorial independence. Contact Editor Scott S. Greenberger for questions: info@stateline.org. Follow Stateline on Facebook and X.
Correction: An earlier version of this story did not include that the advocacy groups’ modeling included one new natural gas plant. The story has been updated.
Xcel Energy’s latest long-range plan for meeting electricity demand in Minnesota includes six new natural gas peaker plants that critics warn could be obsolete before customers are done paying for them.
Comments filed last month by clean energy advocates and the state attorney general’s office push back on the utility’s plan to build a fleet of small fossil fuel plants as it otherwise ramps up clean energy investments. The facilities would operate sparingly, just a few hours at a time on days when the grid is strained and wind, solar and other clean power can’t keep up with demand.
More economical options exist, though, according to a coalition of clean energy groups that hired experts to model alternatives. The study commissioned by the groups concluded Xcel could save ratepayers as much as $3.5 billion by opting for a single new gas plant, and relying more on existing plants, energy storage, efficiency and demand response, and buying surplus power on the regional power grid.
The clean energy groups include Fresh Energy, which publishes the Energy News Network (Fresh Energy’s leadership and policy staff do not have access to ENN’s editorial process.)
The debate is over the utility’s latest integrated resource plan — the first submitted to state regulators since Minnesota Gov. Tim Walz signed legislation last year requiring electric utilities to use 100% clean energy by 2040. Xcel Energy supported the legislation and has proposed various scenarios for achieving the target, but disagreements remain among stakeholders about how to get there, particularly when it comes to cost and equity issues.
Different approaches to modeling
Allen Gleckner, executive lead for policy and programs at Fresh Energy, said Xcel’s gas plant proposal is similar to one in its last integrated resource plan that asked regulators to approve two new peaker plants that would provide as much as 800 megawatts of electricity. Xcel eventually agreed to an open, fuel-neutral bidding process allowing clean energy companies to propose alternatives. That process is still underway, with an administrative law judge expected to make recommendations.
The clean energy groups’ consultants used the same software program as Xcel to arrive at a plan to add a new 374 megawatt gas plant, 3,800-4,800 megawatts of wind, 400 megawatts of solar, and 800 to 1,200 megawatts of energy storage resources by 2030. Extending contracts at existing peaker plants could add 970 megawatts, and energy conservation initiatives could reduce use during high demand times.
Gleckner said Xcel has taken an exceptionally conservative approach by mostly creating scenarios that did not consider electricity being available from neighboring systems or the MISO regional transmission grid. Gleckner said Xcel does not and has never operated as an island, with MISO delivering power to its customers through a shared resource pool.
“Xcel is using a sort of fiction of modeling because the reality is we’re part of a regional grid,” he said.
The result is a plan to “build a bunch of new resources that we know are either not compatible with our state laws or are going to be costly and likely to retire early,” he said.
Amelia Vohs, climate program director for the Minnesota Center for Environmental Advocacy, praised Xcel for not asking regulators to extend the life of existing fossil plants, unlike its counterparts in other states. Unlike previous long-range plans, Xcel’s latest imagines a future in which large gas and coal power plants are not the backbone of the system.
What that grid will look like remains challenging, Vohs said. Adding to the challenge is rising power demand from data centers, manufacturing, and the electrification of buildings and transportation. Even so, Vohs believes clean energy is ready for a leading role.
“It’s a much better solution that’s flexible in this time of uncertainty without making this big commitment to gas resources for the next 40 years,” Vohs said.
Patty O’Keefe, senior field strategist for the Minnesota Sierra Club, said proposed combustion turbine peaker plants pose “significant environmental and public health risks” because they potentially emit more carbon and nitrous oxide than larger, more common combined cycle gas plants. They also tend to be built in communities already suffering higher pollution levels.
The Sierra Club would like Xcel to focus more on energy efficiency than electricity generation in its planning. Efficiency reduces demand and makes “the transition to clean energy smoother and more cost-effective,” O’Keefe said.
Managing risk
Meanwhile, the office of Minnesota Attorney General Keith Ellison has also weighed in, warning that investments made now may become obsolete “stranded assets,” meaning the plants may become uneconomical or forced to retire before they have delivered projected benefits to customers.
Xcel has acknowledged the risk of stranded assets generally in Securities and Exchange Commission filings, though not specifically in relation to its proposed gas peaker plants.
Utilities are incentivized to build power generation because investors earn a return on capital investment. The attorney general argues that if plants become obsolete or transition to other forms of energy, such as hydrogen, Xcel ratepayers should not have to pay for retrofits and other investments it might have to make to reduce emissions.
In its filings to state regulators, Xcel said it is concerned about having enough firm dispatchable power to meet rising demand quickly during certain times of the day. By 2030, the company will have ended its use of coal for energy generation after closing four coal-burning facilities this decade. The proposal suggests Xcel may need to add even more peaker plants between 2030 and 2040.
Xcel spokesperson Kevin Coss said the company will be “adding a significant amount of wind and solar power to our energy mix” and complementing that generation “with always-available generation — power we can supply any time it’s needed — to reinforce the reliability of the grid.”
Coss said Xcel identifies generation sources in a technology-neutral way so it can decide not to use natural gas combustion plants in the future. The current integrated resource plan calls for fewer firm dispatchable resources than the 2019 version, he said.
The conservative modeling “avoids overreliance on the energy market, which could expose our customers to excessive risk,” Coss said.
Residents, businesses and organizations have until Oct. 4 to send comments on the integrated resource plan to the Public Utilities Commission. The commission is expected to make a decision on the plan in February 2025.
Republican Tony Wied didn’t lobby to raise gasoline prices. His association opposed a bill that might have lowered gas prices short term.
Democrat Kristin Lyerly made the lobbying claim Aug. 23, 2024.
Both are running for a Green Bay, Wisconsin-area U.S. House seat in the Nov. 5 election.
Lyerly’s campaign noted Wied, a former gas station owner, was a board member of what used to be known as the Wisconsin Petroleum Marketers and Convenience Store Association.
In 2019, the association lobbied against a bill that would have repealed Wisconsin’s Unfair Sales Act, also known as the minimum markup law.
Wied was not among the association’s registered lobbyists on the bill, which didn’t become law.
The minimum markup law prohibits selling items, including gasoline, below cost, which the law says prevents unfair competition. It requires a minimum markup of 9.18% on gas.
Some conservatives argue the law artificially raises prices.
This fact brief is responsive to conversations such as this one.
The leader of a local anti-solar energy group admitted to Ohio regulators last week that a well-connected natural gas executive is among the group’s largest donors.
The testimony by Jared Yost, founder of Knox Smart Development, offered the fullest view yet of the group’s ties to fossil fuel interests, undercutting its claims to be a “grassroots” advocate for local farmers and other residents.
“It changes the story quite a bit,” said David Pomerantz, executive director of the Energy and Policy Institute, a watchdog group that recently published a report on the fossil fuel industry’s long history of using money and misinformation to stoke local opposition to renewable energy projects.
Knox Smart Development emerged late last year as a high-profile local opponent of the proposed 120 megawatt Frasier Solar project, located near Mount Vernon, Ohio. Questions emerged about its funding source after it hosted a town hall meeting at a local theater with complimentary food and drinks for approximately 500 attendees.
Yost disclosed during an Ohio Power Siting Board hearing last week that one of its largest donors is Tom Rastin, the former vice president of Ariel Corporation, which makes compressors for the oil and gas industry. The Washington Post reported last year that Rastin is also a leader of The Empowerment Alliance, a dark money nonprofit that advocates for the natural gas industry.
Yost said he did not have knowledge about Rastin’s work with The Empowerment Alliance, but said the fossil fuel group provided “non-financial” resources to Knox Smart Development to help oppose the Frasier Solar project.
Yost denied being swayed by corporate interests and said his group has not received corporate funding. “The Empowerment Alliance has nothing to do with me or [Knox Smart Development],” he told the Energy News Network via email. “I have reached out to them and asked questions on a couple of occasions, as can anyone, and as I have done of others.”
Multiple links
When asked in his hearing testimony if Knox Smart Development was “funded by any individuals or entities having any interest or providing any goods or services to the fossil fuel industry,” Yost answered, “No, not directly to the best of my knowledge.”
On cross-examination, however, Yost admitted Rastin was one of the group’s largest funders. Yost is a former IT specialist at Ariel Corporation, and his work supported Rastin’s department. Rastin’s wife, Karen Buchwald Wright, is a former president and CEO of Ariel and continues as board chair. Her son Alex Wright succeeded her in 2021 as CEO.
A July 2024 report from the Energy and Policy Institute includes links to recently produced public records. A September 2023 email shows Rastin was slated to speak to the Ohio General Assembly’s Business First caucus in October. The email attached a copy of Rastin’s biography with The Empowerment Alliance logo on top.
Mitch Given, who was identified in a meeting with Ohio lawmakers last year as The Empowerment Alliance’s Ohio director, spoke at a Knox Smart Development town hall meeting last November. There he was introduced as someone who travels across the state to help farmers and others “find their voice” and push back against solar projects.
The emcee for that town hall event, Tom Whatman, is a chief strategist for Majority Strategies. The Empowerment Alliance’s Form 990 filing for 2023 shows it paid the political consulting firm more than $620,000 that year, making it the group’s highest paid contractor for five years in a row.
Yost last week also discussed a dinner meeting last summer about the Frasier Solar project where the attendees included Rastin, Given, Whatman, Ariel employee Trina Trainor, and Lanny Spaulding. Spaulding is listed as a contact person for The Empowerment Alliance on an Ohio lobbyist registration form. Yost’s dad and others also attended. Yost had earlier said he did not organize the meeting.
Yost denied being influenced by The Empowerment Alliance or other corporate interests.
“No one has ever tried to direct me in any way with my opposition to this project. I am nobody’s ‘puppet’,” Yost told the Energy News Network. “I am doing this for me, my family, my township, and my neighbors.” He also said it was “insulting that people try to question my intentions, integrity, and intelligence. Frankly, it hurts.”
Misinformation at work
Nolan Rutschilling, managing director of energy policy for the Ohio Environmental Council, said arguments presented by behind-the-scenes special interests can be more believable if they seem to come from a grassroots effort.
“People trust their neighbors because they are often believed to not have any outside agenda other than the best interest of their community,” Rutschilling said. “Unfortunately, this allows misinformation to spread quickly, and communities have stopped renewable energy projects from moving forward.”
The stakes are significant, he said, because local public sentiment is among the factors the Ohio Power Siting Board considers in judging whether a project is in the public interest, along with statewide interests.
“If the fossil fuel industry wants to oppose solar projects, they should intervene in the open — not by amplifying misinformation in communities,” Rutschilling said.
“The Empowerment Alliance prefers to stoke fear in hopes of snuffing out perceived competition from clean, cheap, local renewable energy,” said Craig Adair, a vice president for Frasier Solar’s developer, Open Road Renewables. “As always, Frasier Solar stands ready and willing to address local residents’ legitimate concerns about potential impacts of solar development.”
Statements at Knox Smart Development meetings and in ads have included multiple examples of misinformation. For example, Yost admitted during cross-examination he was unaware that a photo showing damaged solar panels was taken in St. Croix after a strong hurricane — a highly unlikely event in central Ohio.
“This was intended to show what I believe could happen,” Yost said.
Other examples include unsupported claims about solar panels and other components releasing toxic chemicals. Steve Goreham, a speaker at the group’s November 2023 town hall, made unsupported claims about climate change. Goreham also drew spurious correlations between electricity price rises and high levels of renewable energy in California and Texas. In fact, wildfires, extreme heat and transmission upgrades were the driving factors.
Misinformation was rife in opposition testimony people gave at three local public hearings held by the Ohio Power Siting Board in Knox County.
Half of more than 100 unique arguments made by project opponents at those hearings were not supported by the facts, said Heidi Gorovitz Robertson, a professor at Cleveland State University College of Law, in her August 22 expert testimony for the Ohio Environmental Council.
“In the aggregate, the arguments do not present credible or compelling opposition to the proposed project,” Robertson said.
Construction is underway in St. Paul, Minnesota, on a major affordable housing development that will combine solar, geothermal and all-electric appliances to create one of the region’s largest net-zero communities.
Twin Cities Habitat for Humanity broke ground in June on a four-block, 147-unit project on the site of a former golf course that’s being redeveloped by the city and its port authority, which made the decision to forgo gas hookups.
Affordable housing and Habitat for Humanity builds in particular have become a front line in the fight over the future of gas. The organization has faced criticism in other communities for accepting fossil fuel industry money and partnering with utilities on “net-zero” homes that include gas appliances. It’s also built several all-electric projects using advanced sustainable construction methods and materials.
The scale of the Twin Cities project is what makes it exciting, according to St. Paul’s chief resilience officer Russ Stark.
“We’ve had plenty of motivated folks build their own all-electric homes, but they’re one-offs,” he said. “There haven’t been many, if any, at scale.”
Stark added that the project, known as The Heights, was made possible by the federal Inflation Reduction Act.
“I think it’s fair to say that those pieces couldn’t have all come together without either a much bigger public investment or the Inflation Reduction Act, which ended up being that big public investment,” he said.
A vision emerges
Port Authority President and CEO Todd Hurley said his organization bought the property in 2019 from the Steamfitters Pipefitters Local 455, which maintained it as a golf course until 2017. When no private buyers expressed interest in the property, the Port Authority bought it for $10 million.
Hurley said the Port Authority saw potential for light industrial development and had the experience necessary to deal with mercury pollution from a fungicide the golf course staff sprayed to kill weeds.
“We are a land developer, a brownfield land developer, and one of our missions is to add jobs and tax base around the creation of light industrial jobs,” Hurley said.
The Port Authority worked with the city’s planning department on a master plan that included housing, and it solicited developers to build a mix of market-rate, affordable and low-income units. The housing parcels were eventually sold for $20 million to a private developer, Sherman Associates, which partnered with Habitat and JO Companies, a Black-owned affordable and multi-family housing developer.
“Early on, we identified a very high goal of (becoming) a net zero community,” Hurley said. “Everything we have been working on has been steering towards getting to net zero.”
Twin Cities Habitat President and former St. Paul mayor Chris Coleman said the project met his organization’s strategic plan, which calls for building bigger developments instead of its traditional practice of infilling smaller lots with single-family homes and duplexes. The project will be the largest the organization has ever built in the Twin Cities.
Coleman said the Heights offered an opportunity to fill a need in one of St. Paul’s most diverse and economically challenged neighborhoods and “be part of the biggest investment in the East Side in over 100 years.”
The requirement for all-electric homes merged with Habitat’s goal of constructing more efficient and sustainable homes to drive down utility costs for homeowners, he said. Habitat built solar-ready homes and sees the solar shingles on its homes in The Heights as a potential avenue to producing onsite clean energy.
Zeroing in on net zero
Mike Robertson, a Habitat program manager working on the project, said the organization worked with teams from the Minneapolis-based Center for Energy and Environment on energy modeling.
“The Heights is the first time that we’ve dived into doing an all-electric at scale,” Roberston said. “We have confidence that these houses will perform how they were modeled.”
Habitat plans to build the development to meet the Zero Energy Ready Home Program standards developed by the U.S. Department of Energy. Habitat will use Xcel Energy’s utility rebate and efficiency programs to achieve the highest efficiency and go above and beyond Habitat’s typical home standards.
The improved construction only adds a few thousand dollars to the overall costs and unlocks federal government incentives to help pay for upgrades, he said.
The nonprofit will receive free or reduced-cost products from Andersen Windows & Doors and other manufacturers. GAF Energy LLC, a solar roofing company, will donate solar shingles for over 40 homes and roofing materials. On-site solar will help bring down energy bills for homeowners, he said.
Chad Dipman, Habitat land development director, said the solar shingles should cover between half and 60% of the electricity the homes need. Habitat plans to use Xcel Energy incentive programs to help pay for additional solar shingles needed beyond those donated.
Habitat will install electric resistance heating technology into air handlers to serve as backup heat for extremely cold days. Dipman said that the air source heat pumps will also provide air conditioning, a feature not available in most Habitat properties in Minnesota.
Phil Anderson, new homes manager at the Center for Energy and Environment, has worked with Habitat on the project. He said the key to reducing the cost of heating and cooling electric homes is a well-insulated, tight envelope and high-performance windows. Habitat will build on its experience with constructing tight homes over the past decade, he said.
“Overall, the houses that we’ve been part of over the last almost ten years have been very tight homes,” Anderson said. “There’s just not a lot of air escaping.”
Habitat’s national office selected The Heights as this year’s Jimmy & Rosalynn Carter Work Project, named after the former president and his wife, two of Habitat’s most famous supporters. The work project begins September 29th and will receive as visitors Garth Brooks and Trisha Yearwood, who now host the Carters’ program.
Robertson said thousands of volunteers from around the country and the world will help put up the homes. The Heights project “raises a lot of awareness for Habitat and specifically for this development and the decarbonization efforts that we’re putting into it,” he said.
The Heights’s two other housing developers continue raising capital for their projects and hope to break ground by next summer. Habitat believes the project will meet its 2030 completion deadline.
Snaking under city streets, behind residential drywall and into furnaces, ovens and other appliances, natural gas pipelines are a ubiquitous presence in U.S. buildings. The question of what to do with them as the planet warms has become a serious debate — dozens of U.S. cities and states have crafted plans to reduce reliance on natural gas, and more than 20 other states have passed laws to preempt that type of regulation.
Now, utilities around the nation have begun testing a controversial idea aimed at reducing the carbon footprint of gas lines, while keeping them in place. Nearly 20 utilities have laid out plans to inject lines with a blend of gas and hydrogen, the latter of which emits no carbon dioxide (CO2) — a major greenhouse gas — when combusted. Testing such blends, these companies say, is an essential step towards understanding the practice, which they argue will help reduce emissions and fight climate change.
Deploying more hydrogen is also a federal priority — the Inflation Reduction Act created a tax credit for hydrogen production, and the Bipartisan Infrastructure Law set aside $9.5 billion to support hydrogen development.
But a federal hydrogen strategy released last year suggests blending hydrogen into gas infrastructure should focus on industrial applications. Many environmental and customer advocates agree; they argue that the use of hydrogen blends in buildings — rather than to power industries that are hard to electrify — makes little sense.
“Every dollar you’re reinvesting into the gas system could be a dollar you’re using to electrify the system,” said Nat Skinner, program manager of the safety branch of the California Public Advocates Office, an independent state office that advocates for consumers in utility regulation. “Finding the right uses for hydrogen is appropriate. But I think being really careful and thoughtful about how we’re doing that is equally important.”
Nearly 30 projects focused on blending hydrogen into gas lines that serve homes and businesses have been proposed or are in operation in more than a dozen states, Floodlight found, and many more utilities have hinted at future proposals. If all are approved, the projects as proposed would cost at least $280 million — and many utilities are asking that customers pay for them.
As regulators consider the proposals, advocates are calling for them to weigh the prudence of the investment. In California — where electric rates have climbed steeply in recent years — the Sierra Club has argued that the projects are “an inappropriate use of ratepayer funds” and “wasteful experiments.”
Blending brings, risks, rewards
Hydrogen blending can be undertaken in a section of pipeline isolated from the rest of the gas network or in a larger “open” system that serves homes. Utilities can inject it in large transmission lines, which ferry gas from processing and storage locations to compressor stations, or into distribution lines, the smaller pipes that bring gas to buildings.
Because hydrogen releases only water vapor and heat when it’s burned, it’s considered a clean fuel. And unlike traditional wind and solar energy, it can produce enough heat to run industrial furnaces. Utilities have framed the fuel as a clear way to slash the emissions associated with their operations.
“These demonstration projects are an important step for us to adopt hydrogen blending statewide, which has the potential to be an effective way to replace fossil fuels,” said Neil Navin, the chief clean fuels officer at Southern California Gas (SoCalGas), in a March statement on its application for hydrogen blending pilots.
Burning hydrogen, particularly in homes, also presents certain risks. Hydrogen burns hotter than natural gas, which can increase emissions of nitrous oxide (NOx), a harmful air pollutant that can react with other elements in the air to produce damaging pollutants including small particulates and ozone.
Hydrogen is a smaller molecule than methane, the main ingredient in natural gas, and can leak more readily out of pipelines. Hydrogen is also flammable. And when certain metals absorb hydrogen atoms, they can become brittle over time, creating risks of pipeline cracks, depending on the materials the pipelines are made of.
There are also outstanding questions about how much hydrogen blending actually reduces greenhouse gas emissions.
Of the utilities that have offered details about the hydrogen source they plan to use for their pilot, roughly half plan to use “green hydrogen,” which is produced using clean electricity generated by renewable sources such as wind and solar. Today, fossil fuels power more than 90% of global hydrogen production, producing “gray hydrogen.”
Most utility blending pilots are targeting blends of up to 20% hydrogen. At those levels, research has shown that hydrogen would reduce carbon dioxide emissions by less than 10%, even when using hydrogen produced with clean manufacturing processes.
Some utilities have estimated the emissions impacts of their pilots. A CenterPoint Energy pilot in Minneapolis using blends of up to 5% green hydrogen was estimated to reduce carbon emissions by 1,200 metric tons per year, which is the approximate energy use of 156 homes. A project in New Jersey testing blends of 1% green hydrogen was estimated to reduce emissions enough to offset the energy use of roughly 24 homes.
Blending gray hydrogen may show no carbon benefit at all, according to some research. That’s in part because hydrogen produces one-third less energy by volume than natural gas, meaning three times the amount of hydrogen is needed to make up for the same unit of natural gas.
And hydrogen requires more energy to manufacture than it will later produce when it’s burned. For these reasons, some environmental groups say hydrogen is an inefficient way to decarbonize homes and businesses; some analysts have called the process “a crime against thermodynamics.”
“There are much better, readily available, more affordable ways to decarbonize buildings in the form of electrification and energy efficiency,” said Jim Dennison, a staff attorney at the Sierra Club.
Advocates including Dennison also worry that investing more in the natural gas system will delay electrification and allow utilities to keep their core pipeline businesses running. “I can see why that’s attractive to those utilities,” he said. “That doesn’t mean it makes sense for customers or the climate.”
‘We’re not sure’ of right mix
While the climate benefits are debated, some research and active projects indicate that burning blended fuel at certain levels can be safe. For decades, Hawaii Gas has used synthetic natural gas that contains 10-12% hydrogen. Countries including Chile, Australia, Portugal and Canada have also run hydrogen blending pilots.
And although pipelines can weather when carrying hydrogen, that’s less likely for distribution lines that reach homes because those pipes are often plastic, said Bri-Mathias Hodge, an associate professor in energy engineering at the University of Colorado-Boulder.
Hodge helped author a 2022 review of technical and regulatory limits on hydrogen and gas blending. With blends below 5%, Hodge said customers are unlikely to face risks or notice a difference in how their appliances or furnaces function.
More uncertainty exists around higher blends. “I think we’re not sure if below 20% or say, from 5 to 20% is safe,” said Ali Mosleh, an engineer at the University of California-Los Angeles who is spearheading hydrogen blend pilot testing with 44 partners, including utilities, to address knowledge gaps in the state.
Although Hodge at UC-Boulder thinks electrification is the more efficient choice for homes, he said the pilots can help utilities get comfortable with blending, which may eventually be applied elsewhere. “It’s not going to really move the needle in terms of decarbonization long term, but it’s a step in the right direction,” he said.
Steven Schueneman, the hydrogen development manager at utility Puget Sound Energy, which serves about 1.2 million electric and 900,000 gas customers in Washington, said incremental approaches like utility blending pilots will signal that hydrogen is a “real industry.” That could help the fuel gain a foothold in other areas, like industrial heat and aviation.
But Schueneman also acknowledges there remains uncertainty around whether hydrogen is the most cost-effective way to decarbonize buildings.
“It’s not clear that blending hydrogen is going to be a prudent decision at the end of the day,” he said.
Puget Sound Energy has conducted two small-scale blending pilots at a test facility. In the future, the utility plans to focus its hydrogen efforts on how blends may function in power plants, rather than in buildings. The nearly 30 blending pilots Floodlight tracked include only projects focused on use in buildings, but other utilities have proposed blending hydrogen at natural gas power plants, where the blend will be burned for electricity.
‘Cost is an essential consideration’
Blending pilots focused on buildings have been spearheaded by some of the largest utilities in the nation as well as smaller-scale gas providers, and are being considered from coast-to-coast.
Dominion Energy, which serves 4.5 million customers in 13 states, has laid out plans for three blending pilots, in Utah, South Carolina and Ohio. National Grid, which has 20 million customers, is pursuing a project in New York. And multiple large California utilities have proposed pilot programs.
Some utilities, such as Dominion and Minnesota-based Xcel Energy, did not reply to several requests for clarification on hydrogen blending plans, or replied to only some queries about their plans. But plans from certain utilities have been detailed in regulatory filings with state utility commissions.
The pilots for which cost data are available range in price from roughly $33,000 for Puget Sound Energy’s small-scale testing (which ratepayers did not fund) up to an estimated $63.5 million for a decade-long pilot proposed by California utility Pacific Gas & Electric (PG&E), which would focus on blending 5% at the start ranging up to 20% hydrogen in transmission gas lines.
If approved, customers would pay up to $94.2 million for PG&E’s pilot, because of the rate of return utilities are able to collect from customers. California utilities are aiming to recover more than $200 million in total from customers for their proposed pilots.
California regulators have rejected some previous blending proposals from utilities, saying companies should use “every reasonable attempt to use existing and other funds before requesting new funds.” Advocates including the Environmental Defense Fund (EDF) have argued that the projects are not in the public interest, particularly amid the state’s spiking utility bills.
“Cost is an essential consideration,” said Erin Murphy, a senior attorney at EDF. “When you’re passing on costs to ratepayers, you have to demonstrate that that is a prudent investment.”
Pilots have gotten pushback in other states, including Colorado and Oregon, where projects were recently dropped or delayed, and opposition has been fierce in California, which has the most pilots proposed to date. The mayor of Truckee, California, which could host a project, submitted a comment to regulators explaining the town does not support it. And following protests at two California universities that planned to collaborate on projects, utilities downsized the plans.
After student opposition at University of California-Irvine, SoCalGas reduced the scope of the project and proposed an additional pilot in Orange Cove, a small agricultural community of about 9,500 people. Ninety-six percent of Orange Cove’s population identifies as Hispanic or Latino, and roughly 47% of residents live below the federal poverty line, according to the U.S. Census.
Some Orange Cove residents also are concerned about blending, which SoCalGas hopes to test at up to 5% hydrogen levels. Genoveva Islas, who grew up there and is the executive director of Cultiva la Salud, a public health nonprofit based in nearby Fresno, said the local approval process lacked transparency and public input.
The project is slated to sit steps away from the Orange Cove football field, near the town’s high school, middle school and community center. “In short, I would just say it is concerning,” Islas said.
In an email, the utility told Floodlight that the city “proactively asked SoCalGas to undertake this project in its community” and said it was “expected to bring socioeconomic benefits to Orange Cove.” The utility also said it hosted a community engagement meeting about the project in Spanish and English and has provided fact sheets to the community in both languages.
That has made some feel like unwilling test subjects in an experiment that others, like the Sierra Club’s Dennison, say are unnecessary. “The community’s immediate reaction is that they don’t want to be guinea pigs,” Islas said. “They do not understand how this decision was made without their involvement or their consent.”
The great majority of the projects, including the one in Orange Cove, are still under review by regulators. Meanwhile, researchers are undertaking more studies to understand the technical limits of blending.
“There are a lot of unknowns,” said Mosleh from UCLA. “Some fundamental research needs to be done.”
Oregon’s plan to regulate fossil fuel companies and reduce greenhouse gases is ready for public comment after being derailed seven months ago by a lawsuit brought by natural gas companies.
Draft regulations for the state’s redo of the 2021 Climate Protection Program were published Tuesday by the Oregon Department of Environmental Quality. The agency gave the public until Friday, Aug. 30 to comment on them. The state’s Environmental Quality Commission, which oversees rulemaking for DEQ, is expected to vote on final rules by the end of the year, once again putting the state’s landmark climate change laws into action.
Little has changed from the original program standards, which were passed three years ago by the commission. The targets for reducing greenhouse gas pollution would remain the same. Under the proposed rules, Oregon would attempt to reach a 50% reduction in greenhouse gas pollution by 2035 and a 90% reduction by 2050 to confront the growing threat of climate change.
Fossil fuel companies would have to gradually decarbonize their energy supply, largely by shifting away from petroleum and natural gas and instead incorporating renewable energy sources such as wind, solar and so-called biofuels – made from captured gas and decomposing matter – into their energy offerings.
Natural gas is almost entirely methane gas, among the most potent climate-warming greenhouse gases that trap heat in the atmosphere. One-third of global warming is due to human-caused emissions of methane, according to the U.S. Environmental Protection Agency.
Under the newly proposed rules, some heavy energy users in the state would need to meet emissions reduction targets and companies would need to show compliance with the program every two years, as opposed to every three years in the original plan.
“We did build off of the work that we already did in the prior Climate Protection Program,” Nicole Singh, senior climate change policy advisor for DEQ, told the Capital Chronicle on Tuesday. “We didn’t throw that out the window. We’re using that information to help inform this.”
To give companies a little flexibility, they would be able meet some pollution reduction targets by purchasing credits sold by the state. Money from those credits are invested in projects that reduce greenhouse gas emissions.
Expanding the program
Besides the three-year compliance schedule, the largest change to the newly proposed rules is who has to follow them.
The state, for the first time, would regulate the emissions of companies that are heavy natural gas users, not just the suppliers of their gas. These include some cement, fertilizer and gypsum producers. Gypsum is in plaster, drywall and some cement. Companies operating in Oregon, including cement maker Ash Grove and Georgia Pacific, which works with gypsum, would need to meet new emissions standards, Singh said.
The agency included other changes in the investment portion of the Climate Protection Program. This section covers what is ostensibly Oregon’s carbon crediting market, where polluters can offset some of their greenhouse gas emissions by investing in projects that reduce overall emissions. One credit would be equal to one metric ton of carbon dioxide released into the atmosphere, and companies could buy them for $129 per credit. This market, which would have begun operating this year, was previously projected to bring in $150 million a year for community decarbonization and renewable energy projects, according to the Portland-based nonprofit Seeding Justice, which had previously been tasked with overseeing the investments.
Credit recipients, largely nonprofits working on community-based projects, could use the grants to help people and businesses buy and install solar panels and heat pumps, purchase electric vehicles and chargers and help weatherize homes and buildings.
Under the proposed rules, Oregon’s nine federally recognized tribes would play a bigger role in determining grants and would receive more funding, according to Singh. It’s unclear yet what role Seeding Justice could play in distributing grants in the future, she said, because such details would follow final rulemaking.
The state would also take a fraction of the funding – about 4.5% – to pay for its oversight of the grants and to undertake internal and external auditing to ensure money is being spent appropriately and that projects are, in fact, reducing the amount of greenhouse gas emissions required.
Under the new rules, companies could offset 15% of their emissions through the purchase of these credits during the first two years of the Climate Protection Program and 20% during each two-year compliance period thereafter. Previously, companies could only offset 10% of their emissions through the credits in the first two years.
DEQ also proposes to work more closely with the Oregon Public Utilities Commission to understand how the Climate Protection Program will affect natural gas rates for Oregonians and to ensure companies aren’t passing all the costs of decarbonization on to their customers.
Lawsuit triggers redo
The Climate Protection Program was approved in 2021 by the Environmental Quality Commission after more than a year of meetings, presentations from the environmental quality department and public comment.
But in December, Oregon Court of Appeals judges agreed with lawyers representing NW Natural, Avista Corporation and Cascade Natural Gas Corporation, who argued that in the process of imposing state regulations to cap and reduce emissions, the commission failed to submit required disclosures to the companies and to other entities that hold federal industrial air pollution permits. The department was required to issue a written statement about why the state was adopting emission limits that exceeded federal rules, disclose a list of alternatives that were considered and explain why they were not adopted.
The judges ruled the program invalid on those technicalities.
Rather than appealing the decision to the Oregon Supreme Court, which would likely not hear the case until mid-2025, state environmental regulators announced in January that they would start over.
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Before pivotal hearings that begin Monday, Duke Energy has made a few small concessions to its plans for a giant fossil fuel buildout in North Carolina, winning over the once-skeptical state-sanctioned ratepayer advocate.
Duke’s proposed settlement with Public Staff and Walmart needs approval from the state’s Utilities Commission to take effect. It comes as dozens of experts plan to appear before the panel to debate the company’s biennial carbon plan, including its controversial bid to invest in 9 new gigawatts of natural gas plants and punt on a key state climate deadline.
The agreement still shows Duke determined to construct five large combined-cycle gas plants in the coming decade, but only three would get a preliminary blessing for now. Public Staff earlier had wanted only one such plant to be considered “reasonable for planning purposes.”
While state law requires Duke to cut its carbon emissions 70% by 2030, in line with scientists’ recommendations for avoiding catastrophic global warming, the agreement stipulates that a pollution cut of that magnitude by decade’s end is “unachievable and presents unacceptable risks to the reliability of the grid.”
Duke also agrees to study the $250 billion Energy Infrastructure Reinvestment Program it had earlier eschewed, though the settlement’s wording seems to reject what experts say is the program’s best use: financing up to 80% of new clean energy projects and remaining debt on retiring coal units with government loans.
Apart from a few other changes around the edges, the settlement is aligned with the plan Duke filed in January. And while the deal means the utility and Public Staff won’t spend time debating each other next week in Raleigh, clean energy groups and other intervenors still have plenty to litigate.
‘A risk of stranded investments?’
Perhaps most notable, critics say the January blueprint, combined with Duke’s spirited defense of it in hundreds of pages of testimony filed July 1, runs headlong into a new federal rule on coal and gas plants finalized in April.
In effect, the rule forces any new large gas plants to run no more than 40% of the time beginning in 2032. Public Staff, the office of the Attorney General and clean energy groups had urged Duke to reconsider its plan in light of the new regulation, perhaps by replacing some or all of the planned gas with renewables or rolling out new initiatives to reduce electric demand.
Duke is suing to try to overturn the new rule, which is now final. But the company avowed that if the regulation remains, its only option was still to build five new, combined-cycle turbines, even if they only ran at half their potential capacity.
Having placed manual constraints on renewables and battery storage in its computer forecasting program, Duke said in its testimony, “the model is not able to shift this ‘lost’ gas generation to renewable resources.”
Instead, the company asserted it would have to generate more power from its existing gas and coal plants, causing 4 more million tons of carbon pollution in the year 2035, a “likely delay” in 70% pollution cuts to 2036 or later, “and an increase in the total system cost of more than $600 million.”
In its July 1 filing, Duke also brushed aside doubt from Public Staff and clean energy groups that its new gas plants could ultimately run on emissions-free hydrogen fuel, which is not yet commercially viable and many experts say may never be practical.
“Several parties incorrectly assume that the addition of new gas resources will subject customers to the risk of stranded investments,” the company wrote in its testimony, “but fail to consider the critical value of these resources over the planning horizon and lack detailed analysis regarding how such a risk would actually materialize three decades from now.”
‘A desperate attempt’
The question of timing also still looms large. Though approval of the settlement would foreclose a 2030 compliance date, clean energy advocates still hold out hope that Duke will make deep pollution cuts consistent with climate science and not delay them until late in the next decade.
In fact, the North Carolina Sustainable Energy Association and three groups represented by the Southern Environmental Law Center were so dismayed by Duke’s July 1 testimony that last week they moved for regulators to declare that they wouldn’t approve a plan that violated state or federal law, before the meat of next week’s expert witness hearings begin.
That provoked a blistering countermotion from Duke. The groups, said the utility, “were inexcusably dilatory in filing their motion, and their desperate attempt to introduce legal and procedural complexity into this proceeding at the 11th hour should be stricken.”
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