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.
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.”
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.”
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.
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.
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.
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.”
Duke Energy has been laying the groundwork for a new gas power plant in North Carolina’s Person County for years, touting it as the “next generation” of electricity production and lining up support from local politicians eager to hold on to the utility’s tax dollars.
With acknowledgement from regulators and even some clean energy experts that new gas infrastructure may be needed as Duke shutters its coal fleet, the long-planned gas turbines once seemed like an inevitability.
But now, the 1,360 megawatt combined-cycle facility poised to replace the company’s aging coal smokestacks on Hyco Lake has become a major point of contention. And while the odds still favor Duke, community members and advocates alike say they have cause for hope.
First, there’s the reality of new Biden administration rules on fossil fuel power plants. Beginning in 2032, any new large, combined-cycle plant like that proposed in Person County must either cut its carbon emissions drastically or run 40% of the time or less.
Because North Carolina’s geology isn’t suited to carbon sequestration and emissions-free hydrogen fuel isn’t yet viable, the company would have to limit the plant’s operations — either making it unavailable at key times or requiring costly startups and shutdowns, said Ridge Graham, the North Carolina program manager for Appalachian Voices.
“Either of these options make this combined cycle plant a bad investment and a much more expensive form of electricity generation than clean or renewable energy sources,” Graham told commissioners at a public hearing in Roxboro last month. “This is especially true for Duke customers as the purchase of gas fuel is passed on and has led to multiple rate increases through riders on electricity bills since 2017.”
Even if the actual fuel costs were cut in half, engineers for the agency said, “total transportation charges would mostly be unchanged within the ‘Fuel’ category because of the significant pipeline costs that would be necessary to provide natural gas service to the Roxboro site.”
In addition to these charges, ratepayers would also have to pay the full cost of the plant, amortized over 35 years, plus Duke’s regulator-approved profit margin, energy analyst Elizabeth Stanton said in written testimony on behalf of Sierra Club, Southern Alliance for Clean Energy, and the Natural Resources Defense Council.
What’s more, she noted, ratepayers would cover whatever “replacement resources” were needed to meet demand “after the facility’s expected generation was decreased.”
In contrast, Stanton says, Duke’s estimated costs for ratepayers assume the plant will run at over 40% capacity through 2042 — a scenario squarely at odds with the new Biden administration regulation.
“Duke needs to account for the rule in their planning, and they have not done that,” Mikaela Curry, a North Carolina-based campaign manager at the Sierra Club, said in an interview. “Who pays for a gas plant that can only run 40% of the time?”
While Public Staff supports the new plant, it also asserts in testimony that Duke hasn’t developed a plan for how it will comply with the new federal rule.
“We have concerns about the impact and implementation of the recently issued [Clean Air Act] Rule,” engineers Dustin Metz and Evan Lawrence wrote. “We cannot yet identify how [the] proposed Roxboro facility may be impacted and to what extent.”
‘That modeling … was flawed’
The agency also hasn’t seen a comprehensive analysis from Duke to justify the location for the combined cycle unit. “The Public Staff cannot say definitively that the proposed Roxboro… project is least cost for [Duke’s] ratepayers,” Metz and Lawrence said in their testimony.
Other critics also question whether the gas plant is Duke’s most economical option, though for different reasons.
In testimony for the environmental groups, Stanton asserts that Duke artificially limits renewables in its carbon-reduction models; assumes clean energy is 60% costlier than industry standards; and, in the plan that most quickly transitions the company away from fossil fuels, makes all resources 20% more expensive. Plus, new generation built before 2030 — which would be mostly solar — gets an 8% penalty.
“Duke’s rationale for requesting the [Hyco Lake plant… is the] selection of gas resources in its least-cost modeling,” Stanton wrote. “That modeling, however, was flawed, including multiple biases for gas resources and against renewable resources.”
Detractors also doubt the company’s plan to convert the gas plant to run on emissions-free hydrogen as late as 2049 – just in time to comply with state law. That “presumption,” said consultant Bill McAleb in testimony on behalf of the Environmental Defense Fund, “is not based on substantive evidence presented in this docket proceeding.”
Detailing an array of challenges, including uncertainty from equipment manufacturers, McAleb concludes a zero-carbon, hydrogen-fueled facility, “is not only speculative but unlikely.”
‘A very nuanced topic’
While advocates wage a legal campaign against the gas plant, activists are reaching out to the people of Person County face-to-face, knocking doors on the roads surrounding the existing coal facility.
Juhi Modi, North Carolina field coordinator for Appalachian Voices, says the canvassing effort so far has identified more opponents than not – surprisingly so.
“Given that it’s a very nuanced topic, and the fact that people appreciate Duke’s economic presence in the county,” Modi said, “it’s been really meaningful to just hear what they think.”
Referencing the yearslong campaign to get Duke to excavate its leaking coal ash pits, Modi added:
“These people were also impacted by coal ash contaminating their well water and were part of a long fight to get their water cleaned up, and still have a lot of skepticism about Duke’s ability to responsibly operate in this community.”
Along an existing pipeline right-of-way, the new pipeline Dominion Energy plans to transport gas to Duke and other customers has also given some in the community pause. Activists say it appears to pass dangerously close to Woodland Elementary School in Semora.
“What would happen if there is an accident? If there is a fire or an explosion?” Modi said. “It’s a real concern for the children, the teachers and the staff that work in the school.”
While cleaner than coal in terms of smog-and soot-forming air pollution, the gas plant’s emissions of methane — a potent greenhouse gas — will negate its climate benefits, said Katie Moore, an air quality researcher who lives in Roxboro.
“Not only do we not have enough time to use [gas] as a ‘bridge fuel,’” she said, but it doesn’t even make sense because the climate impacts are the same, essentially, as coal.”
Moore also believes there’s an incorrect assumption that either Duke replaces its Hyco Lake coal units with gas or the company leaves the county altogether.
“Those are not the only two options,” said Moore, who grew up in neighboring Durham County and moved to slower-paced Person 2.5 years ago. “I don’t want people to be out of jobs and I don’t want to lose 20% of the tax base. But that’s not an inevitability. I think there are lots of ways that we could embrace renewables in this county.”
Long odds remain
Still, at an in-person public hearing last month, Moore and other locals against the plant were outnumbered by supporters, who ranged from tourism boosters to local elected officials to the superintendent of Person County Schools, Rodney Peterson.
“A school district like ours could not recover from the loss of our local tax base,” said Peterson, who noted he was appearing in a personal capacity. “I ask you to remember our students, our parents, our teachers in Person County.”
Besides support from many community leaders, many other factors still weigh in Duke’s favor.
Notwithstanding its concerns about the plant’s cost and its compliance with the new Biden administration rules, Public Staff believes the energy it will provide will be vital as the company works to reduce its carbon pollution as required by law.
“There is a need for [combined cycle and combustion turbine] natural gas generation in [Duke’s] service territories,” the engineers wrote in their testimony. Denying the company a permit to build the plant, they asserted, “could delay interim carbon emissions reduction compliance and coal plant retirements set forth in the Carbon Plan Order.”
While solar combined with battery storage could in theory provide similar economic and energy benefits as the gas plant, Person County leaders would have to repeal a 2022 ordinance that effectively bans large-scale solar farms.
Meanwhile, Duke is eschewing an Inflation Reduction Act loan program meant to encourage clean energy investments in communities with retired coal plants.
And even though the commission is dominated by appointments from Gov. Roy Cooper, a Democrat who’s embraced the clean energy economy and criticized fossil fuels, the panel has so far exhibited little resistance to the utility’s gas expansion plans.
“It just makes me feel sad,” said Crystal Cavalier-Keck, the co-founder of the Indigenous activist group Seven Directions of Service, referencing how the panel approved Duke’s last carbon reduction plan with few edits. “It’s disheartening.”
A spokesperson for Duke declined to comment for this story, but the company’s formal responses to Public Staff and clean energy advocates intervening in the case are due later this month. An expert witness hearing is expected as soon as early August.
In the meantime, organizers like Cavalier-Keck say they’ll keep getting the word out. “We’re just going to continue to knock on all the doors,” she said, “and continue to educate people.”
Since 2021, when North Carolina adopted a law requiring Duke Energy to zero out its carbon pollution, advocates have spent every other year poring over the company’s plans for supplying this state of 11 million with clean electricity.
As of late last month, the first phase of the new ritual is now complete: citizens turned out by the hundreds to public hearings around the state and submitted written comments; and dozens of organizations, businesses, and large customers filed testimony to the state’s Utilities Commission, charged with approving or amending Duke’s plan by year’s end.
A review of these comments shows clear dissatisfaction with Duke’s plan, which critics say is too reliant on gas and unproven technologies and too dismissive of resources like solar and battery storage.
But there are also a few powerful institutions pulling in the opposite direction. And their voices could grow louder in the coming months, as the state enters the next phase of in-person, expert witness hearings.
The law requires Duke to cut its carbon pollution by 70% by 2030 and at least 95% by midcentury, in line with scientists’ recommendations for avoiding catastrophic global warming. The statute directs regulators on the Utilities Commission to develop a plan to make that happen and to update the blueprint every two years.
Even as the popular, bipartisan measure moved through the legislative process, some critics worried it gave too much deference to Duke and did not make clear that regulators — not the utility — would chart the state’s path to a decarbonized electricity sector.
Still, after Duke in 2022 issued its first Carbon Plan proposal — a document covering hundreds of pages and including four different pathways for achieving net zero — a host of outside stakeholders put forward their own plans for the commission to mull, hoping the panel would pick and choose from them or even craft its own blueprint.
But in the end, after months upon months of expert hearings, public input, and thousands of pages of written testimony, the commission adopted Duke’s plan with few edits.
Rather than devise their own painstaking models to compete with Duke and its army of lawyers, engineers, and other experts, this time most organizations are starting with the company’s portfolios and critiquing key elements.
‘Most reasonable, least cost, least risk plan’
As in the lead up to the first Carbon Plan, this year Duke has proposed multiple routes to zero carbon by midcentury, with one clear preference. Offered in January after predicting a steep rise in electricity demand, that pathway is to add over 22 gigawatts of renewable energy and battery storage in the next decade, including from ocean-based wind turbines.
In the same time frame, the company wants to shutter most of its coal plants and add nearly 9 gigawatts of new gas plants, nearly three times the immediate build-out it proffered two years ago and one of the largest such proposals in the country. It also envisions two small nuclear plants of 300 megawatts each, about a seventh the size of the state’s largest nuclear plant outside Charlotte.
The company seeks to exploit exceptions in the state’s law to achieve a 70% cut in carbon emissions by 2035 instead of 2030. And while its plans to zero out its pollution are vague, they rest partially on building more nuclear reactors by 2050 and fueling any remaining gas plants with hydrogen – a technology still under development.
Still, Duke’s focus is on the immediate term. In its January filing, it sought support for “pursuing near-term actions that align with [its preferred pathway] as the most reasonable, least cost, least risk plan to reliably transition the system and prudently plan for the needs of…customers at this time.”
‘Imperative that the 2030 target be met’
Numerous commenters questioned that assertion, including the company’s premise that ratcheting down emissions more slowly than the law prescribes presents a “lower execution risk.”
Perhaps most notably, the Clean Energy Buyers Association, a group of 400 major corporations from a range of sectors with their own sustainability targets, argued forcefully against delaying the 2030 target.
“The ability of [our] members that are Duke customers to meet their clean energy commitments depends in large part on how clean Duke’s resource mix is,” the association’s Kyle Davis said in written testimony. He went on to say regulators should “only” approve a near-term plan that would allow Duke to cut its pollution 70% by decade’s end.
Similarly, a group of local government Duke customers with climate goals, including major cities Raleigh and Greensboro and small college towns Boone and Davidson, noted that Duke’s energy mix would dictate whether they could meet their aims.
“Due to the urgency of the climate crisis and the implications to the health and well-being of the constituents we serve,” the cities and counties wrote, “it is imperative that the 2030 target be met in the timelines specified in [the law.]”
Testifying for the office of the Attorney General Josh Stein, expert witness Edward Burgess noted that the commission has not yet abandoned the 2030 deadline and that, according to the law, the 70% cut could only slip past 2032 under “very specific conditions” that have not been met.
Regulators haven’t authorized a nuclear or wind project that has been delayed beyond Duke’s control, he asserted, and a delay wasn’t necessary to maintain the “adequacy and reliability of the existing grid.”
Recognizing Duke’s latest increased demand projections, Burgess urged commissioners to “set a clear directive for Duke to achieve the Interim Target by no later than 2032.” Otherwise, said the witness for the attorney general, the public interest would be harmed by the “increase [in] the cumulative tons of CO2 emitted, which would remain in the atmosphere for hundreds to thousands of years.”
‘Arbitrary limits on battery and solar’
The process by which Duke maps its generation plans over the next decade is complex and time intensive. But it’s aided by a computer modeling program that weighs various factors including costs to produce an optimal generation mix.
This method produces more solar and battery storage each year than Duke thinks is possible or appropriate to connect to the grid, so the company imposes manual limits on the computer program. Critics call that step unnecessary and damaging to the project of curbing carbon emissions in a least-cost manner.
“Solar [photovoltaic] is the cheapest source of carbon-free electrons on the grid now and for the foreseeable future,” testified expert witness John Michael Hagerty on behalf of the Carolinas Clean Energy Business Association. “All things being equal, the more generation… that Duke can get from solar PV instead of other resources, the cheaper it will be for Duke to comply with carbon reduction targets.”
Michael Goggin, an expert witness for the North Carolina Sustainable Energy Association and clean energy groups represented by the Southern Environmental Law Center, analyzed other grid operators around the country and estimated that Duke could connect around 4 gigawatts of solar and storage annually, compared to the upper limit of 2.8 gigawatts suggested by the utility.
“Duke’s arbitrary limits on solar and battery interconnection should be greatly increased if not eliminated,” Goggin wrote. “These limits do not reflect reality, and there are many potential solutions to the interconnection challenges Duke claims in its attempt to justify these limits.”
Pleading for more offshore wind
While numerous commenters were happy to see Duke move much more ambitiously toward offshore wind than it did two years ago, they noted the utility’s projected 2.4 gigawatts — enough to power about a million homes — fell significantly short of the near-term potential in ocean wind areas off the state’s coast.
“The Carolina Long Bay projects have the potential to reach more than 2 gigawatts, and the Kitty Hawk Projects have the potential to reach nearly 3.5 gigawatts,” two employees of wind company Avangrid testified. “Therefore, there is additional offshore wind resource beyond the Preferred Portfolio request available to North Carolina.”
The state’s Department of Commerce has taken a keen interest in offshore wind because of its vast potential for economic development. Jennifer Mundt, an assistant secretary at the Department, implored regulators and Duke to “set a path forward… that directs the deployment of at least 6.0 gigawatts of offshore wind by the mid-2030s.”
Such development is achievable with the Carolina Long Bay and Kitty Hawk areas, she said, and “will unlock billions in capital expenditures and tens of thousands of good-paying jobs for North Carolinians, and boost Duke towards its mandate to achieve carbon neutrality by mid-century – a true win-win-win scenario.”
A pair of experts testifying for the North Carolina Sustainable Energy Association noted that Duke would benefit from being a “second mover” on offshore wind in the United States: it could learn from the many other projects underway on the Eastern seaboard without putting ratepayers at risk.
In contrast, John O’Brien and Philip Moor warned that for small modular nuclear reactors, “it is unclear when the Companies will be a second mover… the only approved project design…has been cancelled, and the closest designs… are under development by TerraPower and the Tennessee Valley Authority.”
Skepticism of new gas and ‘advanced’ nuclear
Indeed, while most clean energy advocates believe large, existing, emissions-free nuclear power plants can play a vital role in curbing carbon pollution, several say Duke’s near-term pursuit of as-yet unproven small modular reactors over more readily available alternatives is a mistake.
“Given the long lead-times, nuclear experts have found that [small modular reactors] will do nothing to address climate change, as the technology is too little, too late,” Grant Smith, senior energy policy advisor with Environmental Working Group, testified on behalf of his group, Durham nonprofit NC WARN, and others.
Numerous stakeholders criticized Duke’s plan to build 10 new gas plants in the next decade, half of which would be large baseload plants forced by new federal rules to run 40% of the time or less. Not only would Duke customers be on the hook for these underutilized plants, critics argued, they’d also be subject to erratic fuel prices.
“In North Carolina, this volatility was at the heart of hundreds of millions of dollars of recent fuel cost increases approved by the commission,” expert witness Evan Hansen testified on behalf of Appalachian Voices. “The Companies’ proposed aggressive build-out of natural gas-fired power plants will only increase their exposure, and their ratepayers’ exposure, to the future volatility of natural gas prices.”
The company’s strategy of converting gas plants to run on hydrogen molecules separated from other compounds as late as 2049 also strains credulity for some.
“Duke’s general plan to build new natural gas-firing facilities and then transition those facilities to 100% hydrogen-firing faces significant technical uncertainty, infrastructure hurdles and costs,” testified William McAleb for the Environmental Defense Fund. The plants, he said, “are not necessary to maintain grid reliability, may never be co-fired with hydrogen, and will likely raise rates.”
The Clean Energy Buyers Association also suggested that Duke’s plan to supply its members with gas-fired electricity could backfire, causing the state to lose economic development projects and the utility to lose new customers.
“Some of the new load that Duke is forecasting may not materialize if Duke increases the carbon intensity of its resource mix as it has proposed to do in this docket, since some of the customers bringing new load… have clean energy targets,” the association’s Davis wrote.
If that happens, he said, “and Duke overbuilds with fossil fuel capacity, it would result in higher costs for existing customers and make it more difficult for existing customers to meet their sustainability targets.”
Amid all this criticism, support for Duke’s approach stood out, especially where the timeline is concerned.
Testifying for the Carolina Industrial Group for Fair Industrial Rates, a powerful consortium of manufacturers and other large Duke customers, Brian Collins asserted, “there is increased cost and risk in reliably meeting the interim 70% target by 2030. As a result, I recommend that the Commission not require Duke to meet the 70% emission reductions target by 2030.”
Public Staff, the state-sanctioned ratepayer advocate, believes that compliance with the interim pollution cut is possible by 2034 but not before. And the state’s 26 electric cooperatives, which buy electricity wholesale from Duke, expressed some concern about the speed of transmission upgrades necessary to add renewable energy to the grid fast enough.
A technical conference is scheduled for next week in Raleigh, and what is likely to be weeks of expert-witness hearings begin July 22.
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