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OIL & GAS: A think tank’s report documents how the top U.S. gas lobbying groups and two European counterparts have used the same arguments for more than 50 years to promote the continued use of fossil fuels. (OpenSecrets)
ALSO:
ELECTRIC VEHICLES:
NUCLEAR: The success of a newly signed law boosting small nuclear will depend on the makeup of the Nuclear Regulatory Commission, which hinges on the next president, industry experts say. (E&E News)
HYDROGEN: U.S. Senate Democrats call on the Treasury secretary to relax rules for federal hydrogen industry subsidies, which require the use of only clean energy generated at the same time as the hydrogen fuel. (The Hill)
CLEAN ENERGY:
GRID:
CLIMATE: A Baltimore City Circuit Court judge throws out the city’s climate accountability lawsuit against several major oil companies, saying the case sought to go “beyond the limits of Maryland state law.” (Reuters; E&E News, subscription)
HYDROPOWER: An Oregon university begins construction of the nation’s first utility-scale wave power testing site along the state’s central coast. (KOIN)
COAL: Coal-fired power plants are becoming increasingly unreliable because of deferred maintenance, increased cycling and other factors, according to the North American Electric Reliability Corp. (Utility Dive)
CLIMATE:
OIL & GAS: In New Mexico, oil and gas giants partnered with environmentalists and politicians to develop an abandoned well cleanup bill, but turned against the final product and claimed it would “destroy” the state. (ProPublica)
ELECTRIFICATION:
SOLAR: A Wyoming economic development official proposes installing solar arrays on reclaimed Powder River Basin mines to replace lost coal tax revenue and jobs but runs into opposition from residents loyal to fossil fuels. (Inside Climate News)
GRID:
EFFICIENCY: Honeywell debuts a plug-level energy monitor that could help offices realize the energy savings of unplugging devices when they’re not being used. (Utility Dive)
WIND:
ELECTRIC VEHICLES: An organization representing gas station chains calls on Florida officials to begin taking applications for funding to build electric vehicle charging stations. (Tampa Bay Times)
POLITICS: Observers expect West Virginia’s longstanding influence on federal energy policy to fade this fall as Sen. Joe Manchin steps down and is likely replaced by a pro-fossil fuel Republican. (Inside Climate News)
TRANSPORTATION: Illinois health and environmental groups call on the state’s pollution control agency to phase out sales of most gas- and diesel-powered vehicles by 2035. (Chicago Sun-Times)
CLEAN ENERGY:
AIR POLLUTION: The U.S. Supreme Court sides with Ohio and Indiana by pausing enforcement of the Biden administration’s “good neighbor” rule aimed at preventing downwind air pollution crossing state borders. (Associated Press)
SOLAR: A Chicago-based nonprofit offers 10- to 13-week courses that equip disadvantaged workers with job skills for the state’s growing solar industry. (Chicago Sun-Times)
RENEWABLES: Americans’ support for renewable energy and electric vehicles is declining with older Republicans driving the drop in support since 2020, according to a new Pew survey. (Bloomberg)
NUCLEAR:
COAL: Coal plants in Ohio and Indiana have lost hundreds of millions of dollars so far this year as the costs to operate plants grow compared to cheaper alternatives. (Checks & Balances Project)
GRID: New research suggests utility customers could see bill savings of up to 40% when rooftop solar, battery storage and other demand-reducing technologies are deployed. (Inside Climate News)
ELECTRIFICATION: A $2.2 billion hospital under development in Detroit will include a $235 million electric heating and cooling system that would make it just the second all-electric hospital in the country. (Crain’s Detroit, subscription)
COMMENTARY: The head of a biogas advocacy group says capturing methane from landfills, agricultural waste and other sources to produce electricity could help meet growing power demand. (Utility Dive)
The operators of the decades-old energy systems that heat and cool buildings in downtown Minneapolis and St. Paul have ambitious plans underway to reduce emissions.
The mostly hidden networks of insulated pipes connected to centralized heating and cooling equipment are known as district energy systems. They’ve long been championed as an energy efficient way to heat and cool campuses or downtowns, especially in cooler climates.
Many, though, are connected to fossil fuel facilities, and the systems’ high efficiency alone won’t be enough to help schools, cities, and companies meet their goals of eliminating greenhouse gas emissions by midcentury or sooner. Climate pledges by these institutional customers are now driving efforts to repower district energy systems with clean energy.
University district energy systems began initiatives to reduce emissions years ago and “now in the last five years we’re seeing a lot of emphasis on this from cities and towns,” said Rob Thornton, president and CEO of the International District Energy Association.
In Minneapolis, Cordia Energy, the private company that operates the largest downtown district energy system, is replacing natural gas boilers with electric models. And in downtown St. Paul, officials are seeking federal funding for a project to recover heat from a wastewater treatment plant and reduce energy use for a system currently powered by electricity and biomass.
“We’re doing decarbonization at the rate that our customer base is asking for and we can economically withstand,” said Jacob Graff, Cordia Energy’s north region president. Customers connected to its downtown Minneapolis system range from stadiums and high rises to apartments and medical facilities.
The concept of district heating has been around for centuries, with its roots in the networks of hot water pipes built in ancient Rome. Some of the first modern steam-based systems were built in New York in the 1880s. Today, the United States has more than 700 district energy systems heating and cooling buildings in downtowns, universities, medical campuses, towns and communities.
Cordia Energy’s Minneapolis system opened in 1972 to serve the 57-story IDS Center, still the tallest building in Minneapolis. Today, the steam and chilled water system manages seven plants that heat and cool the IDS and more than 100 other buildings, including U.S. Bank Stadium, Target Center, and the convention center.
Hennepin County owns and operates a much smaller district energy system, connected to a downtown trash incinerator, that primarily serves county buildings and Minneapolis City Hall.
District Energy St. Paul began in the early 1980s after then-Mayor George Latimer hired Swedish engineer Hans Nyman to replace the aging steam system with a hot-water central heating system. Latimer wanted to create a national model of district energy and he largely succeeded. District Energy St. Paul has the largest hot water system in the country, with more than 200 buildings.
Together, the two systems serve some of the state’s biggest buildings, which have emerged as the largest source of greenhouse gas emissions in both cities. In Minneapolis, 65% of the emissions are from commercial, multifamily and industrial buildings. St. Paul’s data is similar.
Cordia plans to reduce emissions from its Minneapolis system by 30% by 2030 before reaching net zero by 2050. Xcel Energy’s green tariff program will offset around half the electricity Cordia uses this year, and it wants to buy more credits if they become available.
The company is replacing older engine-driven chillers with electric models at the former Dayton’s department store, where it has operations. Chillers modulate the temperature inside buildings and can be powered by electricity or natural gas. Geothermal is another potential solution being studied.
A potential geothermal project “hasn’t cleared the economic hurdles yet,” Graff said. “I think we’ll eventually get there.”
Minneapolis customers are not alone in seeking to reduce emissions from district energy systems, Graff said. San Francisco will be Cordia’s first system to decarbonize using hydropower from a dam the company owns in Yosemite National Park.
Downtown St. Paul’s district heating system is owned and operated by a company called District Energy, which recently worked with the city and the regional planning agency on a $152 million U.S. EPA grant application to tap heat from a regional wastewater plant for the city’s system. It would include a project with Xcel Energy to pay for an electric boiler and hot water storage.
District Energy president and CEO Ken Smith said half the system already has been decarbonized through biomass, solar thermal and renewable energy credits. An analysis showed that recovering heat from the Metro Wastewater Treatment Plant, which manages 170 million gallons of water daily, could produce 60 megawatts of thermal energy, and heat pumps could lift the temperature up to the system average.
If District Energy receives the Climate Pollution Reduction Grant, the system would go live in 2028 and allow District Energy to provide 92% of energy from carbon-free or carbon-neutral sources, far ahead of its goal of net zero by 2050.
“This certainly would be able to accelerate that by 30 years,” Smith said. “From everything we’ve seen, there’s nothing like this, certainly not in the United States, and I don’t believe there’s anything like it at this scale in Canada, either.”
St. Paul Resilience Officer Russ Stark said District Energy’s emissions represent a small portion of the total greenhouse gases in the city. Still, around 50,000 tons of carbon would be eliminated annually, and that’s “very impactful,” he said.
The wastewater project would allow District Energy St. Paul to expand to more buildings, decarbonizing them in the process, Stark said. Adding clients “is not a simple process but we’ve been talking a lot about that being an exciting part of the project,” he said. “I don’t know how many major city downtowns there are where there’s an opportunity to largely decarbonize most of the downtown in the way that we can.”
A one-size-fits-all solution for decarbonizing district energy systems doesn’t exist, as most are unique based on customers and geography. Not all can be inexpensively retrofitted for electricity, and the ongoing office and commercial real estate fallout from the Covid-19 pandemic adds risk to financing projects.
Thornton, of the district energy association, said electricity pricing can escalate quickly, especially in summer, creating uncertainty in the market. New technology may require more space, different controls and significant staff training. Federal policy remains unclear about what parts of a district energy system would qualify for tax incentives, he said.
Graff ticks off many challenges in decarbonizing Cordia’s Minneapolis operations. Geothermal works well on campuses and in low-slung neighborhoods where the problem of sending steam to the 50th floor of a skyscraper does not exist, Graff said.
There’s not a simple clean power source like natural gas that has the energy density to create and push steam through a network, he said. To illustrate the point during a tour of Cordia’s downtown plant, he pointed to a pipe with a modest circumference and said the natural gas flowing through it provided the heating for much of the system.
Electrification may be a goal of heating and cooling, but offsetting it with clean power is daunting. Cordia would have to install heat pumps capable of drawing more than 400 megawatts from a clean energy source, which would be no small feat, Graff said.
Hydrogen sounds promising but has no track record yet for supplying an entire downtown district energy system, Graff said. Biomass has potential, too, but sourcing enough it to service a sprawling district energy system reliably remains difficult.
Battery storage, microgrids and other technologies could all play a role, but each brings issues ranging from cost to a lack of testing in a district energy environment, at least at the size of the downtown Minneapolis system.
“We have the economy of Minneapolis in our hands, and regional economics depend on downtown Minneapolis,” Graff said “We need a reliable infrastructure that people can count on that can be delivered economically, and it’s our responsibility to do that.”
CLIMATE: Hawaii recognizes children’s constitutional right to a life-sustaining climate and steps up efforts to reach a goal of net-negative emissions by 2045 to settle a youths’ lawsuit targeting the state’s fossil fuel-friendly policies. (Associated Press)
HYDROPOWER: A rural Alaska community prepares to use federal funding to construct a run-of-the-river hydropower project aimed at reducing the village’s reliance on diesel generators. (KTOO)
ELECTRIFICATION: A study finds California utilities could save about $20 billion over the next two decades by electrifying clusters of buildings instead of replacing their aging natural gas pipelines. (Utility Dive)
STORAGE:
UTILITIES:
ELECTRIC VEHICLES:
OIL & GAS:
PUBLIC LANDS: A federal Bureau of Land Management plan to expand protections on some public lands in western Colorado while leaving 855,300 acres open to oil and gas leasing draws mixed reviews from advocates. (news release)
GRID: California’s grid operator begins shifting governance of its extended day-ahead power market to an independent entity. (RTO Insider, subscription)
BIOFUELS: Nevada researchers find prickly pear cactus fruit are a climate-resilient source of biomass for fuel production. (news release)
COAL: A Wyoming explosives maker says declining Powder River Basin coal production has driven down its sales by 19% this year. (Cowboy State Daily)
COMMENTARY: A California editorial board calls on state lawmakers to require cooling equipment in residential rental units to keep occupants safe during increasingly frequent climate change-exacerbated heat events. (Los Angeles Times)
Biogas projects at wastewater plants serving Columbus and Cincinnati will offset roughly 50,000 metric tons of greenhouse gas annually, according to city officials.
The Columbus Department of Public Utilities estimates biogas cogeneration projects for its Southerly and Jackson Pike plants will reduce greenhouse gas emissions by about 34,000 and 13,000 metric tons of carbon dioxide equivalents, respectively. That’s the equivalent of taking 10,100 passenger vehicles off the road, said Robert Priestas, administrator for the department’s division of sewers and drains.
The utilities also can get back millions under the Inflation Reduction Act if they meet conditions by the end of this year.
“Climate change is upon us, right? And so we have an opportunity to actually make a difference,” said Stacia Eckenwiler, who serves as assistant administrator for the division. She spoke at the Ohio State Bar Association’s Environmental Law Institute in April.
Columbus’s wastewater utility accounts for a significant chunk of the city’s greenhouse gas emissions, she noted. A 2019 inventory report shows water and wastewater accounted for about 9% of nearly 11 million metric tons of carbon dioxide equivalents from community-wide emissions that year.
The Metropolitan Sewer District of Greater Cincinnati is also planning to use biogas to make electricity and provide heating for its Little Miami Wastewater Treatment Plant. The facility still needs to add equipment to generate and capture the biogas to shift some greenhouse gas emissions away from where wastes are now landfilled, and offset some fossil fuel emissions from energy otherwise used at the plant.
Sewage treatment plants remove solids and harmful pollutants from wastewater. Most often, the cleaned-up water goes into a river, lake or other water body near the treatment plant, generally pursuant to permits issued under the Clean Water Act. Leftover sludge containing biosolids has generally ended up in incinerators or at landfills.
Burning of biosolids releases carbon dioxide to the air, and landfilling biosolids likewise releases greenhouse gas emissions. Both options cost sewer plants money to dispose of the wastes.
Anaerobic digestion is another option. Basically, it composts the biosolids to speed up their chemical breakdown. Solids left at the end can generally be added to soil or used in other ways. The process also produces biogas, which is primarily a mix of flammable methane and carbon dioxide. Burning the methane can power an electric generator and also provide heat energy.
In contrast to methane from natural gas, which is a fossil fuel that contributes to human-caused climate change, the methane from wastewater sludge is generally considered clean energy when it’s used for electricity and heating.
The gas is generated anyway, explained Karine Rougé, CEO of Veolia North America’s Municipal Water services. So, using it works as “a perfect substitute” for fossil fuels, she said. Veolia is not involved in the Cincinnati or Columbus projects.
Beyond that offset, “the methane in natural gas is extracted from subsurface rock formations from a depleting source that cannot be replenished,” said Diana Christy, the director of the Metropolitan Sewer District of Greater Cincinnati. In contrast, biogas is renewable, “in the sense that humans always will produce waste.”
Columbus already has a composting program, which began several years ago after stricter regulations meant it could no longer use old incinerators. Now, “all of the biosolids that are produced by our facilities go back to the earth and get used again,” Eckenwiler said. Uses include compost and fertilizer for tree farms.
So far, however, the city has just burned the biogas with a flare. “It’s a wasted resource overall,” she says. That’s set to change.
Biogas projects at the Southerly and Jackson Pike wastewater treatment plants will provide “about half the energy that is necessary at each of our facilities, so it’s a pretty significant amount,” Eckenwiler said. “And that will take that reliance off the grid,” which can help at times of peak demand.
Besides advancing sustainability and the cities’ decarbonization goals, sewer utilities for Columbus and Cincinnati see the projects as a way to reduce costs and respond to shifts in regulatory requirements.
The technology for anaerobic digestion has been around for years, but it has improved recently, Christy said. “Most simply for us, the ‘why now’ is it was an economic decision and the changes in requirements for incineration that we were facing previously.”
Eckenwiler estimated Columbus’s biogas projects will save the city roughly $1 million for the two plants’ energy costs — about half of what they currently spend while biogas is otherwise vented to the air.
She also noted the federal government’s efforts to reduce emissions from the oil and gas industry. “It’s only a matter of time before wastewater utilities are going to be part of that as well,” she said.
The Inflation Reduction Act provides an added economic incentive through its changes to the federal Investment Tax Credit. Previously the credit benefited only people and organizations that paid taxes. The changes now let government units and nonprofits get money back as a reimbursement when projects are finished.
The 2022 law also expanded the Investment Tax Credit to more types of energy projects, including biogas. To qualify, biogas projects must begin construction by the end of this year. The law also provides a “safe harbor” if there’s a commitment to buy at least 5% of the necessary equipment and it is in significant fabrication by or before December 31, Eckenwiler said.
The Jackson Pike project is already under construction and should finish up by sometime next year, Eckenwiler said. The Southerly project is on track to start construction this year and should be complete by 2028.
Cincinnati plans to start construction at the Little Miami plant this year under a design-build contract that lets construction begin while various details are finalized, Christy said. The district is also evaluating the safe harbor provision and considering a purchase of equipment for $11 million before the end of this year, with expected delivery before April of 2024.
The Jackson Pike project for Columbus is estimated to cost about $30 million, Eckenwiler said. “The project at Southerly is part of a much larger project, but the cogeneration portion is about $79 million.” The Investment Tax Credit could provide rebates up to 50%. That includes bonuses for paying prevailing wages and using domestic content, as well as a bonus for projects in or next to an “energy community.”
Parts of Cincinnati’s project that qualify for the Investment Tax Credit could provide up to $50 million in reimbursements, Christy said. Whatever the amount is, “the impact of a direct cash payment from the federal government will serve to reduce the cost burden on local ratepayers as the sewer district reinvests in infrastructure to maintain levels of service and to improve the sewer system in order to better serve the community and to comply with the Clean Water Act.”
Rougé sees a broader trend towards wastewater plants using biogas for energy. In Europe, a prolonged drought and the war in Ukraine have ramped up interest in local energy production, she said. And energy costs have been a major driver in the United States, she said. A desire to boost resilience also weighs in favor of adding biogas or other onsite generation, particularly in states where grid issues already present problems, she added.
Onsite biogas projects may not be cost-effective for some smaller sewer utilities. Yet the Inflation Reduction Act’s deadline is sparking lots of conversations with Veolia’s clients, Rougé said. And even if a wastewater authority doesn’t begin a project yet, other funding support could be available, such as state revolving funds under the Clean Water Act, she said.
Wastewater treatment plants are “complex and technical places,” Eckenwiler said. “They’re also very, very cool resource recovery facilities.”
Duke Energy is already under fire in North Carolina for its plan to blow off a state deadline to curb carbon pollution while also building a massive new fleet of fossil fuel plants.
Now, the company’s blueprint is locked on a collision course with fresh rules from the Biden administration, which target coal and new natural gas plants and take effect in eight years.
“Duke is going to have to go back to the drawing board,” said David Neal, senior attorney with the Southern Environmental Law Center, “and come up with an alternative that is compliant with the rules.”
While much focus on the long-awaited Biden rules has centered on coal, their impact on natural gas is arguably more significant. Duke isn’t alone among American utilities in being forced to re-examine long-term generation plans as a result.
“We think it’s important for every utility and every commission to take a step back,” said Amanda Levin, director of policy analysis with the Natural Resources Defense Council.
But even as the federal regulations underscore a law unique to the state, it’s not clear if North Carolina regulators will take a beat – or even if there’s time for them to corral Duke and an array of stakeholders to rework, vet, and approve a new carbon reduction and long-range plan due by the end of the year. That’s why many advocates say debate over the utility’s immediate next steps will be crucial.
“It’s going to be important to adopt a near-term action plan that really is ‘least regrets,’” said Neal, who’s representing numerous clean energy groups in the proceeding on Duke’s generation plans. “The new rules just put further emphasis on what we already knew was true: we’re going to have to accelerate the adoption of clean resources.”
Duke’s existing fleet of natural gas-fired plants aren’t affected by the new Biden rules. Nor are the smaller gas plants Duke proposes to occasionally satisfy peak demand and serve other limited roles on the electric grid.
But the company plans at least five large, combined-cycle plants in the Carolinas that are impacted by the rules. The four projected for North Carolina include a 1,360-megawatt plant in Roxboro, about an hour north of Durham, for which state regulators are now weighing a permit application.
Natural gas is a fossil fuel, but Duke deems the Roxboro plant and others like it essential to the zero-carbon electricity future that state law mandates by 2050. These baseload generators can back up sources like wind and solar to ensure reliability. At the point of combustion, they produce about half the carbon pollution of coal. And in theory, hydrogen molecules separated from chemical compounds could ultimately supplant gas as a fuel, bringing the plants’ carbon emissions down to almost nothing.
“Natural gas is available 24/7 — with fewer emissions than coal and at a lower cost than renewables alone,” Duke said on its website this year, around the time it asked regulators for permission to build the Roxboro plant. “The new [Roxboro] units would be designed to operate on carbon-free hydrogen in the future.”
But critics say this rationale is flawed in virtually every respect. The cost of natural gas is on the rise, and one recent study showed it was a major driver of recent Duke rate hikes in parts of North Carolina. In December 2022 during Winter Storm Elliott, gas plants failed when they were needed most — in the wee, frigid hours before the sun rose — helping to cause rolling blackouts that impacted half a million customers in the state. Drilling and transporting gas leaks methane, a greenhouse gas 80 times more powerful than carbon, nearly canceling out reduced carbon pollution from smokestacks.
As for hydrogen, experts believe it can serve a small role in a zero-carbon economy — but mostly not in the power sector. Even if it’s carbon-free when burned, hydrogen made from fossil fuels is hardly nonpolluting and also inefficient. Hydrogen fuel produced from renewables should be reserved for limited applications, they say, such as long-distance aviation fuel or to power the few gas plants still running in the middle of the century.
“In our modeling,” said Levin, “hydrogen in the power sector is used just for that last 5% of the decarbonization of the entire grid.”
Still, the power plant rules promulgated by Biden’s Environmental Protection Agency don’t wrestle with reliability, ratepayer impacts or even methane leakage. They cover carbon dioxide pollution alone, and they’re designed to reduce what’s emitted from the smokestack by 90% beginning in 2032.
That limit is based on carbon capture — in which carbon dioxide is sequestered underground rather than released into the atmosphere — a technology widely viewed as infeasible in North Carolina because of its geology. And while other techniques that would achieve the same pollution cuts are allowed under the federal rules, none are yet ripe.
One candidate is now being developed at utility scale in Texas but won’t be deployed until at least three years from now. As for hydrogen, it would have to fuel 96% of Duke’s new baseload gas plants beginning in 2032 to meet the emissions limit — an impossible feat according to the company’s own communications with regulators.
Duke’s current forecast shows its gas fleet running on about 3% hydrogen beginning in 2041, then “holding steady until significantly more hydrogen is required to meet carbon-neutral by 2050,” to comply with state law. And in a brief discussion of the impending federal power plant rules in its August draft of its long-term plan, Duke noted:
“Hydrogen is an important and potentially transformational fuel for the future of the resource portfolio, [but] the volumes necessary to utilize the hydrogen compliance pathway are not thought to be achievable on the timelines presented.”
Thus, if regulators allow Duke to build large new baseload gas plants, the company can only run them 40% of the time or less, beginning in 2032 and until technology becomes viable to slash their emissions.
The Roxboro plant, which Duke plans to put into service at the beginning of 2029, would operate at its planned capacity for just three years in that case. Afterwards, its vaunted ability to provide around-the-clock electricity would be severely curtailed.
Multiply the Roxboro conundrum by five, and the mismatch between the Biden rules and Duke’s gas ambitions becomes clear.
In its August discussion of the expected Biden rules, Duke said it considered running its new combined-cycle baseload plants at 50%. Making up for the resulting difference between demand and supply, including building another large gas plant that would run at half-speed, would require an extra $3.6 billion, the company estimated.
Tyler Norris, a former vice president at Cypress Creek Renewables and a PhD candidate at Duke University, estimates that if the 6,800 megawatts of baseload gas plants Duke announced in January were planned to run at 75% and had to ratchet down to 40% operations, the difference would be greater still. Filling it only with solar could require 9,500 megawatts of capacity in a single year — nearly double what’s online in Duke’s territory today.
“That’s probably on the high end,” said Norris, but, “it’s a pretty huge gap. Something’s going to have to change in the plan.”
Then, there’s the question of whether it makes sense for ratepayers to pay to fill that gap, especially if they’re also shelling out full price for underutilized plants.
“We’re all paying for these plants that admittedly have to sit idle more than half of the time?” asked Dave Rogers, deputy director for the Sierra Club’s Beyond Coal campaign. “Should customers really be forced to pay for those?”
Adhering to the Biden rules on coal plants appears more straightforward.
Duke must shut down its entire coal fleet by the start of 2039, and any plants still running in 2032 must be fired partially with gas. The utility already plans to meet that deadline for eight of its 12 remaining coal smokestacks, covering six sites. Two outliers in Belews Creek, just outside Winston-Salem, can already be fueled with gas. That leaves two units in Roxboro, about an hour north of Durham, that the utility now plans to keep online until 2034.
“The logical thing is to retire that coal plant at least a couple of years earlier. Whatever replaces it will be lower cost,” said Rogers. “That’s the big thing in front of the commission as it pertains to the [coal plant] rules.”
Timing also looms large. State law requires Duke to curb carbon emissions 70% by 2030, with two years’ wiggle room. If regulators authorize a nuclear or wind project that causes logistical delays beyond Duke’s control, the postponement could be indefinite. The company now hopes to exploit the latter loophole, with its preferred path to net zero achieving the 70% benchmark by 2035 or even 2037.
With their deadline of 2032, however, the Biden rules help bolster the case for Duke to rein in its carbon emissions sooner. Doing so wouldn’t just make it easier for the utility to meet the ultimate goal of near-zero emissions by midcentury. It would also significantly reduce overall carbon levels in the atmosphere.
“The thing about climate is it’s not just about achieving net zero in one year and one year only,” said Levin. “Climate is a cumulative emissions problem. If you’re doing status quo until the year you’ve made a net zero commitment, you’re not consistent with a 1.5 or 2 degree warming trajectory.”
Still, while advocates have long pressed Duke to build more battery storage, solar, and wind in place of gas and coal, making the switch in the complex utility modeling tools is no simple task, with a host of variables involved — from transmission capacity to reliability to siting.
“Duke has already submitted its modeling twice now. I doubt that either North or South Carolina commissions will want to do another round of that at this point,” said Maggie Shober, research director for the Southern Alliance for Clean Energy, on a recent webinar about the Biden rules. But, she added, “this will absolutely come up in the process before the [North Carolina Utilities] commission.”
For its part, Duke hasn’t indicated any plans to re-do its projections.
“While we are analyzing the final rules, our view is that [they do] not change our path forward in North Carolina as we continue retiring our coal plants and supporting the state’s unprecedented growth with an all-of-the-above approach that’s designed to deliver affordability and reliability for customers,” company spokesperson Bill Norton said in an email. “Natural gas remains an essential resource in this diverse mix that can be dispatched to meet demand 24/7.”
If that position holds, and state regulators don’t seek to change it, it raises the stakes considerably for the “near-term action plan” expected as part of the plan due by the end of the year, as well as the permit application pending right now for the Roxboro plant.
That short-term plan, said advocates, shouldn’t just account for the risk of new gas resources and the timing of coal retirements, but also allow for more renewables by removing the annual connection caps Duke proposes for both battery and solar.
“I think this is an excellent opportunity,” said Norris, “to revisit the potential to achieve a higher interconnection rate for zero-carbon resources.”
Climate activists and legislators in Massachusetts are pushing a series of bills aimed at stopping further expansions of the natural gas system in the state.
The proposed legislation attempts to build on a groundbreaking order late last year that set the explicit policy goal of transitioning the state from natural gas. The bills include measures to prohibit the construction of more pipelines, stop expansion of service into new cities and towns, and encourage the growth of utility-scale networked geothermal projects.
“The order said they need legislative changes to fully implement their directives,” said Jess Nahigian, state political director for the Massachusetts Sierra Club. “We need to see something out of the legislature this year that moves us towards meeting our legal reductions mandates.”
Massachusetts has set a goal of going carbon-neutral by 2050. A considerable obstacle, however, is the prevalence of natural gas as a heating source: More than half the homes in the state use natural gas as their primary heating fuel. So in 2020, state regulators launched an investigation into the future of natural gas in the state and what utilities’ role would be in the transition from fossil fuels.
After two and a half years of filings, arguments, and deliberation, the state released an order in December 2023 that many hailed as transformational for its clear vision of transitioning from natural gas and holding utilities accountable for reducing emissions. The document laid out a set of principles to guide the process, leaving utilities, regulators, and legislators to build out the specifics.
That’s what some lawmakers are pushing for with the current slate of bills.
House Bill 3237 would stop utilities from bringing natural gas into municipalities that don’t already have service. While most cities and towns are already served by gas pipelines, several dozen, largely in central and western Massachusetts, are still without service. The bill would also prohibit state regulators from approving proposals to build new pipelines to import more natural gas until at least 2026.
Another bill proposed in both the House (H.3203) and Senate (S.2105) contains measures to facilitate home electrification and the development of utility-scale networked geothermal, systems that use thermal energy below the earth’s surface to heat and cool buildings. The legislation redefines a “gas company” as an entity that provides either natural gas or thermal energy, and specifies that the companies’ legal obligation to provide service can be met by natural gas, or alternatives such as heat pumps or networked geothermal.
The legislation would also create a fund that could be used to help low- and moderate-income residents switch from gas to electric appliances. The fund could also pay to retrain gas utility workers to build and maintain geothermal pipes and infrastructure, creating more secure employment for these workers during the transition away from natural gas.
“That way they can gradually transition to this new system while not being laid off, while still being able to feed their families,” said Audrey Schulman, co-founder of HEET, a nonprofit that champions networked geothermal developments.
A third bill, H.3227, would allow any city or town to prohibit fossil fuel use in new construction or major renovations. A 2022 clean energy law created a pilot program allowing these bans in 10 municipalities that had previously voted for the policy. Several additional cities and towns, however, came forward after the law was passed, expressing interest in enacting such rules. Climate activists have long argued these communities — and any additional municipalities that vote for the measure — should be allowed to enact their own bans.
Supporters of these bills point to the environmental impacts of burning less fossil fuel, but also make an economic argument in favor of restricting the growth of gas. The economics of gas companies’ current course of action just doesn’t make sense, advocates argue. Any new infrastructure built now — when the state has explicitly declared a move away from natural gas — is likely to become unneeded or underused long before the normal end of its lifespan. Ratepayers would be left continuing to pay for an obsolescent system.
“Should we be building this infrastructure now that, as we transition off of gas, will be a stranded asset in the ground?” asked Cathy Kristofferson, board member of the Pipeline Awareness Network of the Northeast.
At the same time, the utilities recently filed their grid modernization plans, seeking approval to pass on about $2.4 billion in costs to consumers. While these plans are necessary to make the grid ready for the electrified future, they will inevitably increase costs for consumers, said Sen. Michael Barrett, co-chair of the Senate telecommunications, utilities, and energy committee. It makes sense to take steps to keep natural gas costs in check, he said.
“You do that by making sure that new pipes that take 30 years to pay off don’t go into the ground unless they’re absolutely necessary,” Barrett said. “If you’re going to maximize the electric system you should minimize the gas system. There’s a nice balance there.”
Some, however, argue the push against natural gas is going too far, too fast. Many homebuyers prefer gas for both cooking and hearing, said Emerson Clauss III, a board member and past president of the Home Builders and Remodelers Association of Massachusetts. Though some studies have found minimal cost increases, Clauss says many association members find all-electric homes considerably more expensive to build than houses with gas hook-ups. As the state grapples with a serious housing shortage, new policies should not make it more expensive to build homes, Clauss said.
“I don’t know how we resolve our housing crisis without some good planning and options — and that’s what they’re taking off the table,” he said. “At the end of the day, we have to get people into housing they can afford.”
Advocates generally expect provisions from these individual bills to be wrapped into an omnibus climate bill. Sen. President Karen Spilka at the end of April declared plans for the Senate to tackle a major, comprehensive climate bill, led by Barrett and majority leader Cynthia Creem, before the session closes at the end of July.
“I hope large parts will make it into any omnibus bill,” Schulman said. “This is the time.”
OIL & GAS: The U.S. EPA is reportedly considering tougher emissions rules for new gas power plants ahead of their expected final release this month — a contrast with other Biden administration environmental rules that have generally been weakened after their initial proposal. (Washington Post)
ALSO:
CLEAN ENERGY: Renewable energy generation breaks records across the U.S., including in Texas, where wind energy and solar are toppling coal generation, and New England, which set an emissions-free power generation record in March. (E&E News, subscription; Houston Chronicle, Concord Monitor)
ELECTRIC VEHICLES: The nation’s first fully battery-powered tugboat is set to begin operating from California’s Port of San Diego later this spring. (Canary Media)
PIPELINES:
OFFSHORE WIND: The demise of several Northeast offshore wind projects last year sent Senate Majority Leader Chuck Schumer into a lobbying frenzy that resulted in a modified tax credit to benefit developers and the approval of new projects. (E&E News)
GRID:
COAL: The Army Corps of Engineers says it should be able to open a limited-access channel by the end of the month to access Baltimore’s port, through which a notable chunk of the country’s coal exports pass. (Daily Record)
SOLAR: Indigenous advocates protest a proposed solar development in central Washington state, saying it threatens cultural resources. (High Country News)
COMMENTARY:
PIPELINES: South Dakota ethanol companies offered meals, swag, and other perks to busloads of people to influence lawmakers on carbon pipeline legislation last month, raising legal and ethical questions from critics. (Argus Leader)
ALSO:
ELECTRIC VEHICLES: Purdue University partners with an Indiana agency and the private sector to build the country’s first highway segment that could wirelessly charge electric vehicles as they travel. (Indianapolis Star)
BATTERIES:
SOLAR:
UTILITIES: AEP Ohio residential customers will pay about $10 more per month in higher transmission fees while those same rates for businesses and large industrial users will go down. (Columbus Dispatch)
NUCLEAR: Momentum is building behind nuclear energy in Michigan as lawmakers seek to support the industry, regulators study the benefits and risks, and top state and federal officials plan to reopen a shuttered plant. (Michigan Advance)
GRID:
COMMENTARY: A University of Kansas doctoral student says boosting energy efficiency in rental housing would deliver environmental, economic and social benefits. (Kansas Reflector)
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