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An array of critics came out swinging in January when Duke Energy first filed its plans in North Carolina for one of the largest fossil fuel investments in the country.
But as the months have dragged on in the development of the company’s biennial carbon-reduction plan, some notable detractors have relented.
Just before expert witness testimony was set to begin in Raleigh late last month, the state-sanctioned ratepayer advocate, Public Staff, and Walmart endorsed a settlement with Duke on its blueprint, which includes building 9 gigawatts of new natural gas plants that the utility says could be converted to run on hydrogen in the future.
A few days later, the Carolinas Clean Energy Business Association, a consortium of solar and wind developers, announced it had signed on too.
The agreement, which contains some small concessions from the utility, led to low-key hearings that ended in less than two weeks. It makes it more likely that Duke will get what it wants from regulators by year’s end, including a greenlight, if not final approval, for three large new natural gas plants in the near term.
Chris Carmody, executive director of the Carolinas Clean Energy Business Association, says the proposed compromise also helps lock in forward progress on solar energy and batteries, however incremental.
“It’s a more aggressive solar spend. It’s a more aggressive storage spend,” he said. “Certainly, we would like to see more. But first of all, we like to see it going in the right direction.”
Clean energy advocates believe Duke’s push for new gas plants will harm the climate, since the plants’ associated releases of planet-warming methane will cancel out any benefits of reduced carbon pollution from smokestacks. At the same time, they say the investments could become useless by midcentury or sooner, before their book life is over, saddling ratepayers with costs that bring no benefits.
“There’s not much in it for their customers except unnecessary risk, cost, and more pollution,” Will Scott, southeast climate and clean energy director for the Environmental Defense Fund, wrote in a blog last month.
But Duke’s gas bubble has proved hard to burst. For one, the company’s predictions of massive future demand from new data centers are based in part on confidential business dealings that are challenging to rebut from the outside.
Unlike two years ago, when Duke proposed its first carbon reduction plan, no groups produced an independent model showing how Duke could meet demand without building new gas.
“We can talk about costs, or market conditions,” said Carmody. But, he said, “we did not do any modeling.”
Public Staff ran its own numbers and has urged more caution on new gas plants than Duke proposes. But the agency is unwavering that at least some are needed.
New Biden administration rules haven’t yet proved the death knell for gas that some expected. Duke is suing to overturn the rule, but it insists that building new plants that will run at half capacity is the most economical plan for compliance.
And even as Duke is proffering more gas, it’s also undeniably proposing more solar.
Clean energy backers still object to annual constraints on solar development the utility says are necessary. But the limits have increased from less than 1,000 megawatts per year in 2022 to over 1,300 megawatts. And the settlement would result in another 240 megawatts of solar than Duke had first proposed.
“It’s an iterative improvement,” said Carmody.
What’s more, the settlement opens a discussion with Duke about the scores of 5-megawatt solar projects across the state whose initial contracts will soon expire. A proposal for how to refit them could come in April of next year.
“This is a really important issue to our members,” said Carmody. “These are projects that could be repowered. They could be upgraded with storage. They could have significantly more efficient solar technology than was on them 15 or 20 years ago.”
Still, Carmody said his group tried to word the settlement in a way that left room for clean energy advocates to continue to advocate for less gas and steeper emissions cuts sooner — and that’s certainly their plan.
“Three power plants that will be really expensive to build and then operate for only a few years is just a ridiculous proposal,” the settlement notwithstanding, said Maggie Shober, research director for the Southern Alliance for Clean Energy.
“We remain hopeful that there’s a lot that the [commission] can do in this carbon plan proceeding and in their final order, to move us forward on a clean energy trajectory.”
Nick Jimenez, senior attorney for the Southern Environmental Law Center, acknowledges the settlement stacks the deck somewhat against his clients.
“Historically, the commission approves a lot of settlements,” he said. “It likes to see parties settle, especially when Duke and the Public Staff are involved.”
STORAGE: A growing number of Americans are buying home battery storage systems to counter power outages occurring as the grid faces higher demand and more extreme weather. (Associated Press)
GRID:
ELECTRIC VEHICLES:
EFFICIENCY: The U.S. Energy Department announces $53.6 million to expand weatherization efforts and clean energy installations benefitting low-income communities in 13 states and the Virgin Islands. (Utility Dive)
WIND: New Mexico is emerging as a wind energy powerhouse, trailing only Wyoming in new capacity this year, as state officials approve two new leases that could add another 550 megawatts. (Renewable Energy World, Albuquerque Business Journal)
FOSSIL FUELS: Rhode Island regulators decide that a liquefied natural gas facility that was supposed to only operate temporarily can stay online for another five years, despite the community’s noise, light and climate pollution concerns. (Newport Daily News)
COMMENTARY: A sustainability advocate says Los Angeles will need an “epic transportation reboot” to achieve a zero-emission Olympic Games in 2028. (Los Angeles Times)
Xcel Energy is proposing a new approach to powering the grid in Minnesota.
The utility recently told state regulators it wants to build a network of solar-powered energy storage hubs, located strategically on its grid and linked with technology so they can be operated in concert with each other.
The result would be what’s known as a “virtual power plant.” By simultaneously discharging the batteries, for example, the collection of distributed resources can function similar to a conventional power plant.
It’s a solution some clean energy advocates have long pushed for as an alternative to larger, centrally located projects that are more reliant on long-distance transmission and create fewer local economic benefits. Xcel’s new embrace of the concept likely reflects the evolving economics of clean energy and the urgency to replace generation from retiring coal-fired power plants.
“I welcome our now-agreement about the importance of distributed energy resources in their future procurement plans,” said John Farrell, director of the Energy Democracy Initiative at the Institute for Local Self-Reliance.
Virtual power plants use sophisticated software and technology to aggregate energy from batteries, smart thermostats, electric vehicles, storage and other connected devices. The clean energy nonprofit RMI predicts virtual power plants nationally could reduce peak loads by 60 gigawatts and cut annual energy expenditures by $17 billion by 2030.
Several utilities, as well as solar and storage companies, have developed virtual power plant programs around the country. Perhaps the best-known is National Grid’s ConnectedSolutions program in New England, which includes residential batteries, electric vehicle batteries, and thermostats.
In May, Colorado Gov. Jared Polis signed legislation requiring Xcel Energy to create a virtual power plant plan in that state by next February.
Xcel is pitching the Minnesota project on its own as part of its latest long-range resource plan. In a recent Public Utilities Commission filing, Xcel proposes combining 440 megawatts of solar power with 400 megawatts of battery storage at dispersed locations. Designed to be flexible, the program might add backup generation and energy efficiency measures in the future.
A virtual power plant, Xcel said, would save ratepayers money, improve reliability, accelerate clean energy development, and reduce energy disparities by playing assets in underserved communities. The “new approach equips us to confidently meet incoming load growth, deliver unique customer and community value, and support economic development,” the company said in its filing.
Kevin Coss, a spokesperson for the company, said the proposal “is part of a larger plan to better serve the grid and our customers while meeting anticipated growth in energy demand. The program would grow our distributed energy resources as a complement to our existing plans for additional utility-scale renewable and firm dispatchable generation to advance the clean energy transition.”
Clean energy advocates say the approach could reduce Xcel’s need to build more infrastructure at a time when electricity demand continues to grow and its fleet of aging fossil fuel plants reach closure dates.
A recent study in Illinois suggested that pairing solar with storage could be the most economical and environmentally beneficial way to maintain grid reliability as the state transitions to 100% clean energy.
“Utilities always treated distributed energy resources as something that happened to them and that they had to figure out how to accommodate because they were being told to,” said Will Kenworthy, Vote Solar’s Midwest regulatory director.
The company’s interest in more distributed resources could lead to a more flexible grid, one that helps mitigate substations congestion and allows it to store energy from wind farms for use during high-demand periods, Kenworthy said.
One area of disagreement between the utility and some clean energy advocates is who should own the facilities. Unlike in Colorado, Xcel is proposing to own the Minnesota solar and storage hubs itself, collecting money to build them — plus a rate of return — from ratepayers.
That’s not the best deal for customers, and it prevents local communities and developers from being able to share the financial benefits of distributed energy, said Farrell, of the Energy Democracy Initiative. If Xcel owns the virtual power plant, the cost could be higher than they would be with an open, competitive process.
Farrell pointed to the recent opposition to an Xcel electric vehicle charging plan in which it sought to own all of the chargers. Convenience stores and gas stations argued Xcel had an unfair market advantage as the incumbent utility and would own too much of the state’s charging network. Xcel withdrew the proposal in 2023 after regulators reduced the charging network’s size.
As Xcel’s plan evolves, Farrell wants Xcel to allow businesses, homeowners, and aggregators to also participate by selling their battery capacity or demand response into the program.
The Minnesota Solar Energy Industries Association, which promotes battery storage, also takes a dim view of Xcel owning a virtual power plant.
“This is an area where competition would likely provide better service, lower cost and more choice to ratepayers,” said regulatory and policy affairs director Curtis Zaun. “Monopolies are not particularly good at providing the best service at a reasonable rate because that is inconsistent with their investors’ interests.”
Virtual power plants are different than demand response, such as thermostat savings programs, in that they add value to the grid “without any change needed to the homeowner’s behavior,” said Amy Heart, senior vice president for policy at Sunrun, a home solar and storage company that participates in virtual power plants in the Northeast and in Texas, California, and Puerto Rico.
Heart said the “devil is in the details” when creating a robust demand response program. A program in Arizona failed, she said, because of the underperformance of the single company it selected to aggregate resources.
Sunrun developed a virtual power plant in four New England states, enrolling more than 5,000 solar and storage customers to share their capacity on the grid. In the summer of 2022, Sunrun’s virtual power plant shared more than 1.8 gigawatt hours of electricity.
Typically, Sunrun customers agree under contract to share a portion of their battery backup 30 to 60 times annually for three hours or less for each event. The process is automated, with Sunrun’s software connecting to customer batteries and sending utilities power during high-demand times or predictable peak loads. Customers receive payment for the electricity provided.
Heart said the best systems are open to individual customers and aggregators using different battery storage brands. Giving a virtual power plant “room to grow, breathe, and adapt will be important,” she added.
The Xcel virtual power plant proposal is part of the multi-year Upper Midwest Integrated Resource Plan, which regulators have been reviewing and will likely approve, with many changes, later this year.
TRANSIT: New York’s governor says she’ll have a new Manhattan congestion tolling plan by the end of the year following her decision to delay the original plan, citing London’s gradual toll increase as a possible model. (Newsday)
ALSO: Some New Yorkers worry about the impact heavy rains will have this hurricane season on the city’s subway system, recalling station evacuations and floods that have occurred despite the city’s resilience efforts. (The City)
WIND:
SOLAR:
GRID:
COAL: Two top coal producers, Arch Resources and Consol Energy, plan to merge to form Core Natural Resources, which will be based out of the Pittsburgh suburb where Consol currently has its headquarters. (Associated Press)
NUCLEAR: In Massachusetts, the firm decommissioning the Pilgrim nuclear plant claims the state has no right to stop it from discharging radioactive water into Cape Cod Bay. (WBUR)
ELECTRIC VEHICLES: A Rhode Island startup wants more boaters to swap their gas-guzzling outboard engines for their quiet, battery-powered models. (Boston Globe)
RENEWABLE POWER: New York’s energy research agency grants almost $200,000 to the Finger Lakes village of Montour Falls for a small solar array, an electric truck and other renewable investments. (Finger Lakes 1)
AFFORDABILITY: Some Connecticut ratepayers are arguing for a boycott of the public benefits charge amid rising utility bills. (Hartford Courant)
ELECTRIC VEHICLES: Ford scraps a new electric vehicle model and pushes back the start of production from 2025 to 2027 at its BlueOval electric vehicle and battery factory in Tennessee so it can use lower-cost battery technology. (Tennessee Lookout; Commercial Appeal)
SOLAR:
COAL:
OIL & GAS:
HYDROPOWER: Duke Energy wants to further expand a South Carolina pumped storage battery project after recent upgrades that added 320 MW of capacity. (Greenville News)
POLITICS:
HYDROGEN: West Virginia U.S. Sens. Joe Manchin and Shelley Moore Capito cut the ribbon on a state office for the Appalachian Regional Clean Hydrogen Hub. (Parkersburg News and Sentinel)
BUILDINGS: Developers in Austin, Texas, increasingly build with climate change in mind and aim to partner with electric utilities given the fragility of the state power grid. (Austin Monitor)
UTILITIES:
COMMENTARY: Recent calls by West Virginia’s oil and gas industry to remove regulatory constraints disingenuously promise lower energy prices while exacerbating climate change and downplaying its effects on residents who live near projects like the Mountain Valley Pipeline, writes an environmental activist. (Parkersburg News and Sentinel)
STORAGE: Illinois lawmakers consider establishing energy storage incentives as a new study suggests ramping up storage may be the most realistic path for maintaining grid reliability as the state phases out fossil fuels. (Energy News Network)
ELECTRIC VEHICLES:
CLEAN ENERGY:
UTILITIES: CenterPoint Energy issues a request for proposals from developers to build hundreds of megawatts of renewable energy and other generation sources as part of its long-term energy strategy in Indiana. (Utility Dive)
GRID:
WORKFORCE:
COAL: Consumers Energy will soon offer public tours of a coal plant along Lake Michigan that’s scheduled to be decommissioned within the next year. (MLive, subscription)
COMMENTARY:
A major expansion of battery storage may be the most economical and environmentally beneficial way for Illinois to maintain grid reliability as it phases out fossil fuel generation, a new study finds.
The analysis was commissioned by the nonprofit Clean Grid Alliance and solar organizations as state lawmakers consider proposed incentives for private developers to build battery storage.
“The outlook is not great for bringing on major amounts of new capacity to replace the retiring capacity,” said Mark Pruitt, former head of the Illinois Power Agency and author of the study, which suggests batteries will be a more realistic path forward than a massive buildout of new generation and transmission infrastructure.
The proposed legislation — SB 3959 and HB 5856 — would require the Illinois Power Agency to procure energy storage capacity for deployment by utilities ComEd and Ameren. Payments would be based on the difference between energy market prices and the costs of charging batteries off-peak, to ensure the storage would be profitable. The need for incentives would theoretically ratchet down over time.
“As market prices for power go up, your incentive goes down,” Pruit said. “The idea is to provide an incentive that bridges the gap between the cost of battery technology and the value in the market. Over time, those will equalize and level out.”
The bills, introduced in May at the end of the legislature’s spring session, would amend existing energy law to add energy storage incentives to state policy, along with existing incentives for nuclear and renewables.
The study noted that Illinois will need at least 8,500 new megawatts of capacity and possibly as much as 15,000 new megawatts between 2030 and 2049, with increased demand driven in part by the growth of data centers. Twenty-five data centers being proposed in Illinois would use as much energy as the state’s five nuclear plants generate, according to nuclear plant owner Exelon’s CEO Calvin Butler Jr., quoted by Bloomberg.
The North American Electric Reliability Corporation (NERC) found in its summer and winter 2024 assessments that within MISO and PJM regional grids, Wisconsin, Michigan, Minnesota, Illinois and Indiana are all at “elevated” risk of insufficient capacity.
“NERC, PJM, MISO and the Illinois Commerce Commission have all identified the potential for capacity shortfalls,” said Pruitt. “You do have some options for alleviating that. You can build transmission and bring in capacity from outside the state. You can maintain your current domestic generating capacity [without retiring fossil fuel plants]. You could expand your domestic generating capacity. And an independent variable is your growth rate. All these have to work together, there’s no silver bullet. We know there are major challenges on each of those fronts.”
The latest PJM capacity auction results showed capacity prices increasing from $28.92/MW-Day for the 2024/25 period to $269.92/MW-Day — a nearly 10-fold increase — for the following year. That “translates into an annual cost increase of about $350 for a typical single-family household served by ComEd,” Pruitt said. “The increase in costs indicates that more capacity supply is required to meet capacity demand in the future.”
There are many new generation projects in the queue for interconnection by MISO and PJM, but many of them drop out before ever being deployed because of unviable economics, long delays, regulatory challenges and other issues. A recent study by Lawrence Berkeley National Laboratory noted that while interconnection requests for renewables have skyrocketed since the Inflation Reduction Act, only 15% of interconnected capacity was actually completed in PJM and MISO between 2000 and 2018, and experts say similar completion rates persist.
“This finding indicates that deploying sufficient new capacity resources to offset [fossil fuel] retirements is not likely to occur in the near term,” said Pruitt. “Just because something is planned doesn’t mean it gets built.”
Meanwhile the state is running out of funds for the purchase of renewable energy credits (RECs) that are crucial to driving wind and solar development. The 2024 long-term renewable resources procurement plan by the IPA shows the state’s fund for renewables reaching a deficit in 2028, so that spending on RECs from renewables will have to be scaled back by as much as 60%.
Long-distance transmission lines could bring wind energy or other electricity from out of state. But planned transmission lines have faced hurdles. The Grain Belt Express transmission line, in the works for a decade, was in August denied needed approval from an Illinois appellate court. The transmission line, proposed by Invenergy, would have brought wind power from Kansas to load centers to the east.
“That sets it back years,” Pruitt said. “Transmission is a very long-term solution. I’m sure people are working diligently on it, but it’s five to 10 years before you get something approved and built.”
Pruitt’s study found that if 8,500 MW of energy storage were deployed between 2030 and 2049, Illinois customers could see up to $3 billion in savings compared to if they had to foot the bill for increased capacity without new storage. The savings would come because of lower market prices in capacity auctions, as well as investment in new transmission and generation that would be avoided.
Pruitt found that $11 billion to $28 billion in macro-level economic benefits could also result, with blackouts avoided, reduced fossil fuel emissions and jobs and economic stimulus created.
Pruitt’s analysis indicates that the incentives proposed in the legislation would cost $6.4 billion to customers. But the storage would result in $9.4 billion in savings compared to the status quo, hence a $3 billion overall savings between 2030 and 2049.
“Solar is great, but solar is an intermittent resource; battery storage when paired with solar allows it to be far more reliable,” said Andrew Linhares, Central Region senior manager for the Solar Energy Industry Association. “Battery storage is not as cheap as solar, but its reliability is its hallmark. Combining the resources gives you a cheap and reliable resource.”
“Solar and storage is this powerful tool that can help reduce costs for consumers and create new jobs and economic activity,” he continued. “I don’t believe that same picture is there for building out new natural gas resources. Anything that helps storage, helps solar and vice versa. CEJA sees these two technologies as being joined at the hip for the future, they are being seen more and more as a single resource.”
GRID: New England public advocates say they’re concerned with the structure and cost of Eversource’s proposed $384 million transmission line upgrade project, which they say is overkill given that much of the line is still in good shape. (NHPR)
FOSSIL FUELS: A Bitcoin miner in upstate New York sues the state after being denied an air permit renewal for the gas plant powering its operations. (Gothamist)
SOLAR:
BATTERIES: A Hydro-Québec subsidiary says its first utility-scale battery energy and storage system in the U.S., a 3 MW facility in Troy, Vermont, is now operational. (news release)
BUILDINGS: New York’s governor is “facing pressure on all sides” amid final rulemaking that aims to set emissions standards for refrigerants in commercial refrigerators, residential heat pumps and chillers over the next decade. (E&E News, subscription)
BIOENERGY: In Pennsylvania, a renewable natural gas plant at a Bethlehem landfill officially opens, with enough capacity to heat 14,000 homes. (Lehigh Valley News)
ELECTRIC VEHICLES:
AFFORDABILITY: Connecticut’s U.S. House delegation wants the state’s utility commission to help alleviate financial pressure on residential ratepayers facing high utility bills. (Hartford Courant)
POLITICS: A New Hampshire newspaper details how the state’s four gubernatorial candidates have described their future climate and energy policies. (New Hampshire Bulletin)
COMMENTARY:
OIL & GAS: Researchers find highly elevated oil and gas-related air pollution in a mostly Latino Permian Basin community, but federal regulators have yet to intervene. (Capital & Main)
PUBLIC LANDS: Utah files a lawsuit seeking control of some 18.5 million acres of unappropriated federal lands in the state, claiming Biden administration regulations hamper oil and gas and other development. (Associated Press)
COAL: The U.S. EPA tentatively rejects parts of Utah regulators’ plan to reduce smog-forming emissions from two coal power plants in the central part of the state. (E&E News, subscription)
GEOTHERMAL: California regulators extend the public comment period for proposed geothermal plants near the Salton Sea after environmental justice groups raise concerns. (Holtville Tribune)
SOLAR: A company brings a 200 MW solar installation online to help power its gold mine in Nevada. (news release)
WIND:
CLEAN ENERGY:
GRID:
UTILITIES: Montana regulators order NorthWestern Energy to provide more information before they will consider the utility’s proposed rate hike. (Daily Montanan)
CLIMATE:
ELECTRIC VEHICLES: California awards a San Francisco Bay Area ferry service $5 million to install floating charging stations. (RTO Insider, subscription)
BIOFUELS: A western Colorado county supports studying the feasibility of establishing sustainable aviation fuel production facilities in the region. (Biofuels Digest)
The pair of 1950s-era coal plants bailed out under Ohio’s House Bill 6 law are likely to remain unprofitable even after a surge in grid operator payments to generators, experts say.
The PJM Interconnection grid market makes capacity payments to line up power to meet expected demand in the years ahead. Aging, uneconomical coal plants are being retired at a time when data centers and manufacturers are starting to use more electricity, causing future power generation prices to rise.
But even record-high prices in PJM Interconnection’s recent capacity auction won’t cover the hundreds of millions of dollars in subsidies paid by ratepayers to cover Ohio utilities’ costs for the Ohio Valley Electric Corporation’s Kyger Creek and Clifty Creek power plants.
“Even with a super high price, OVEC is still going to be in the red,” said Neil Waggoner, Midwest manager for the Sierra Club’s Beyond Coal campaign.
The ratepayer subsidies are a result of HB 6, the 2019 state law at the heart of the largest corruption scheme in Ohio’s history. Republican legislative leaders have blocked all efforts to repeal the coal subsidies from coming to a floor vote.
This year alone, ratepayers are on track to pay nearly $200 million to prop up the two plants, one of which is in Indiana. By 2030, total ratepayer costs from the bailout could exceed $1 billion, according to RunnerStone, a consultant for the Ohio Manufacturers’ Association.
Starting next summer, the payments for generators to be ready to supply electricity when PJM Interconnection needs it will jump to about nine times the current rate for most of the grid operator’s service region.
“Put simply, the market pays participants for the promise to produce electricity when called upon by PJM,” said Daniel Lockwood, a spokesperson for the regional grid operator. An auction sets the levels for each year’s capacity payments, and the payments go to generators that bid the clearing price or less.
A spokesperson for the power plants did not directly answer the Energy News Network’s question about whether both cleared the latest PJM auction, although he described the auction results as “positive.”
“The auction results were a positive development for the OVEC plants and are more broadly a signal to the market that additional generation resources are needed in the PJM region,” said Scott Blake, a spokesperson for American Electric Power and Ohio Valley Electric Corp. While the HB 6 rider charges depend on multiple factors, the impact of the 2025/2026 capacity pricing “is expected to be positive for customers,” he said.
AEP is OVEC’s largest shareholder, along with other utility companies in Ohio and other states.
HB 6’s OVEC subsidies currently require Ohio’s residential utility customers to pay between $1.30 and $1.50 per month, depending on whether their utility is owned by AEP, AES Ohio, Duke Energy or FirstEnergy, according to PUCO data from spokesperson Brittany Waugaman. Businesses pay for the rider, too. The HB 6 rider’s net total costs last year were more than $148 million.
While capacity payments will reduce the OVEC plants’ total costs to Ohio ratepayers, the revenue won’t, in itself, make the plants profitable.
Expert testimony from a Michigan case last year found the OVEC plants would need capacity payments averaging about $418/MW-day for several years to become economical. Last month’s record-high price that will take effect next summer was about $270/MW-day.
Economic analyst Devi Glick of Synapse Energy Economics testified in the case on behalf of the Sierra Club.
“To massively oversimplify the economics of the OVEC plants, there are two categories of costs and two categories of revenues,” Glick told Energy News Network. “Costs are on one side of the equation and revenues on the other.”
Based on then-current projections for costs and energy market revenue, Glick calculated what the plants’ capacity revenues would have to be for the equation to balance out.
Several caveats would apply, Waggoner acknowledged, including any differences from last year to this year that could affect projected energy revenues. Nonetheless, he noted, a significant gap would remain.
Glick’s estimate of about $418 as a break-even capacity price for the OVEC plants is realistic and may even be conservative now, said John Seryak, managing partner for RunnerStone.
“PJM is no longer paying for a coal plant’s full power capacity anymore under new rules it created just prior to this capacity auction,” Seryak explained. “That could mean that OVEC needs even higher-priced capacity and energy to be profitable.”
“Future energy market prices, OVEC’s future coal costs, and OVEC’s environmental compliance costs will also be important factors determining the extent of its losses or profitability,” Seryak continued. “All that said, we do not anticipate OVEC operating at a profit without further price increases.”
Blake emphasized the OVEC plants’ role as a “reliable generation resource for our customers and for our region,” adding that the HB 6 rider “ensures that customers in Ohio receive electricity from OVEC for what it costs to produce it and the funds are used to pay down debt with no proceeds going to shareholders.”
That’s not exactly correct, said attorney Kimberly Bojko at Carpenter Lipps, who represents the Ohio Manufacturers’ Association in cases at the Public Utilities Commission of Ohio. “Customers pay the cost to operate and run OVEC and the power produced from OVEC is then sold into the wholesale electric market,” she said. Any revenue offsets the costs of HB 6’s coal subsidy.
The Ohio Manufacturers’ Association also has disputed the use of the HB 6 rider to pay down the OVEC plants’ debt in cases before the PUCO.
“By using ratepayer funds to pay down its debt, AEP Ohio is essentially shifting its bad debt to the Ohio ratepayers,” Seryak said. “It’s akin to if a person forced their neighbor to pay for their mortgage payment.”
“Customers pay for more than just OVEC’s debt, though,” Seryak added. “Customers also pay for losses in the energy market OVEC incurs. When this occurs, it means the electric grid does not need OVEC for reliability. Instead, OVEC is burning coal pointlessly at a loss and charging it to Ohio’s ratepayers.”
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