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 29^th 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.

A St. Paul, Minnesota Habitat for Humanity project will offer affordable housing without fossil fuels is an article from Energy News Network, a nonprofit news service covering the clean energy transition. If you would like to support us please make a donation.

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.

In Colorado, where Xcel Energy had planned to blend hydrogen in an isolated neighborhood, some residents learned of the pilot from a journalist reporting on the project.

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.”

Utilities are trying hydrogen-blended fuels. There are a lot of unknowns. is an article from Energy News Network, a nonprofit news service covering the clean energy transition. If you would like to support us please make a donation.

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.

Redo of Oregon program to cap greenhouse gas pollution ready for public review is an article from Energy News Network, a nonprofit news service covering the clean energy transition. If you would like to support us please make a donation.

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.”

The commission denied both motions.

Before key hearings in North Carolina, Duke Energy makes tiny concessions to big gas ambitions is an article from Energy News Network, a nonprofit news service covering the clean energy transition. If you would like to support us please make a donation.

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.”

Bolstering that concern, Public Staff, the state’s ratepayer advocate, notes that Duke lists a proposed new pipeline to transport gas to the plant as an operating cost that would “presumably” be recovered through the fuel rider.

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.”

Can a long-planned Duke Energy gas plant in North Carolina be defeated? is an article from Energy News Network, a nonprofit news service covering the clean energy transition. If you would like to support us please make a donation.