By Kari Lydersen for Energy News Network.
Broadcast version by Joe Ulery for Indiana News Service reporting for the Solutions Journalism Network-Public News Service Collaboration

Indiana ratepayers spend hundreds of millions of dollars per year for power from coal plants that are operating despite the availability of cheaper sources, including wind and solar.

The state is emblematic of a larger problem, as electricity market rules typically allow utility-owned power plants to essentially cut in line even when they are not the most economical option for customers.

A recent report commissioned by the Natural Resources Defense Council examined how this phenomenon plays out in the Midcontinent Independent System Operator (MISO) regional transmission organization specifically, building on previous research by RMI, the Union of Concerned Scientists and others — all of which show that uneconomic coal plant dispatch takes a huge toll on ratepayer wallets and public health. 

The problem happens primarily with vertically integrated utilities or municipal utilities and cooperatives, which can recoup costs of fuel and operations from ratepayers even if they are operating at a loss. In most of MISO territory, energy markets have not been restructured as open markets, making such cost recapture the norm. 

The NRDC study showed that Indiana ratepayers bore the second-highest burden in MISO, paying $338 million for uneconomic coal power from 2021-2023, just behind Louisiana’s $341 million. North Dakota ratepayers spent an extra $120 million, Wisconsin $69 million, and Minnesota $54 million, the study found. 

Indiana’s R.M. Schahfer plant, run by utility NIPSCO, cost ratepayers more than $100 million in such uneconomical dispatch from 2021-2023, the NRDC study found. 

In an ongoing rate case, Duke Energy is seeking to increase reliance on its Gibson and Cayuga plants in Indiana. These plants were responsible for $29 million and $7.6 million in uneconomic dispatch costs to consumers in 2023, according to RMI’s economic dispatch dashboard. 

“This has been a problem plaguing Indiana coal plants for many years, it’s costing our consumers in Indiana millions of dollars and it’s one of the factors driving rates higher and driving clean energy off the grid,” said Ben Inskeep, program director for Citizens Action Coalition in Indiana. “It’s a tale of utilities making bad decisions as part of their profit motive and then utility regulators failing to hold them accountable as they’re supposed to. Certainly utilities should be operating their plants efficiently and economically, and when they fail to do so, they shouldn’t be getting cost recovery.” 

Duke spokesperson Angeline Protogere said the study misses important context. 

“There are a lot of considerations that go into plant dispatch decisions, and the priority is always reliability of service and economics,” Protogere said. “We weren’t able to replicate the NRDC data, but it appears it’s based on incomplete information. For example, there are times when MISO calls on a unit because of grid reliability needs. There’s a bigger picture that’s not reflected here.”

Skewed markets

The NRDC study found that over three years across MISO, about 400 MW of wind power was curtailed in favor of power from coal plants generating at higher-than-market costs. 

Power producers bid into regional energy reverse-auctions for real-time and next-day power, offering the price for which they can produce their electricity. Grid operators like MISO and PJM are supposed to dispatch the power starting with the most affordable option, until demand is met. 

Even if vertically integrated utilities are not selling their power on the open market but rather serving their own customers, they still need to be dispatched by the grid operator to send their energy onto the grid. 

But under the rules for MISO and other grid operators, coal plants can “self-commit” to run for a given time period even if they cannot produce power below the market rate. The idea is that coal plants can’t ramp up or down quickly, so they may need to keep running at a certain level to be ready to provide more power when needed.

If this relatively expensive coal power weren’t on the grid, more wind power would be purchased and demand for new renewables would likely be created. 

“That increment of power would be filled through the market selecting the next highest bidder,” providing “an accurate picture of what electricity should cost that gives a signal that incentivizes newer generation,” explained James Gignac, Union of Concerned Scientists Midwest senior policy manager. 

The lower the energy prices at a given time and the lower the demand, the worse the coal plant dispatch problem gets. Data from RMI and a 2020 report by the Union of Concerned Scientists shows that ratepayer losses due to uneconomic coal dispatch were lower in 2022, because Russia’s invasion of Ukraine caused natural gas prices to spike, making coal more competitive by comparison. Conversely, when energy demand plummeted in 2020 because of the pandemic, uneconomic dispatch of coal plants soared. 

Since 2015, the uneconomic dispatch of coal plants has cost Indiana ratepayers $1.9 billion and ratepayers nationwide $20 billion, according to RMI’s dashboard. 

The issue has real impacts on the growth of renewables, experts note. If the practice was prevented, market prices would be higher and there would be more incentive for renewable developers to build projects to sell their power on the open market. Meanwhile if vertically-integrated utilities were not allowed to recoup their costs for uneconomic dispatch, they would be motivated not to run coal plants and might decide to invest in building renewables instead, or at least buy wind power on the open market.

“I’ve talked with [wind] developers who say they look at where coal plants self-commit uneconomically, and they avoid those transmission lines because they know they will be curtailed,” said Joseph Daniel, principal in RMI’s Carbon Free Electricity team and lead author of the Union of Concerned Scientists report. 

That report shows that if uneconomic coal dispatch was avoided, Indiana customers would save money — but not as much money as ratepayers in other states, because there is less wind power available around Indiana. Over time, a market unfettered by uneconomic coal plants might correct this situation. 

“The greatest immediate savings for customers from stopping uneconomic coal plant operations are in areas where there are existing low-cost resources such as wind power being curtailed by that behavior,” said Gignac. “If the replacement for the uneconomic coal generation is something like a relatively higher-cost gas plant, then the market clearing price is higher and customer savings are not as significant. However, that higher clearing price is a signal and an incentive for low-cost renewables to locate projects in that area and deliver further cost savings. 

“Removing the market distortion of uneconomic coal operations helps move us toward the cleaner, lower-cost energy system we need.” 

Solutions

Studies show that coal plants that sell their power on the open market – known as “merchant” plants – rarely decide to operate when they are not getting market prices at least equal to their cost of operating – the way vertically-integrated or publicly-owned coal plants do when they know they can recoup their costs from ratepayers, without compensation from the market. In other words, merchant plants do not ask grid operators to be uneconomically dispatched. 

These merchant plants nonetheless seem to ramp up in time to operate when their power is needed, experts note, indicating that vertically-integrated plant operators in MISO are understating their ability to ramp up and down quickly, as noted by NRDC policy analyst Dana Ammann and other experts.

“There’s so little incentive to ramp up quickly, because the market really accommodates their inflexibility,” said Ammann, lead author of the recent NRDC study. The vertically-integrated coal plants in MISO are “much less flexible than coal plants in other markets. In PJM you see coal plants turning on much more quickly, since the merchant plant operators are reliant on the price signals to turn a profit. They don’t have the guaranteed rate recovery, so they’re very responsive to price signals.” 

State utility commissions can prevent regulated utilities from recouping costs when coal plants are dispatched uneconomically. Michigan regulators did exactly this last year in a rate case for Indiana Michigan (I&M) Power, preventing the utility from passing on such costs for its share of the Rockport coal plant, located in Indiana.

Daniel said Indiana regulators should likewise protect Indiana customers from paying for uneconomic power from the Rockport plant. The RMI dashboard shows that plant dispatched $142 million worth of such power last year. Meanwhile the Michigan ruling could be considered precedent for Michigan utilities like DTE and Consumers Energy in future rate cases. 

Ammann noted that states can also use the Integrated Resource Plan process to curb uneconomic dispatch, as Minnesota’s utility commission did when it recently decided that Otter Tail Power’s Coyote coal plant can only recoup costs during a designated power emergency.

“It’s an interesting approach for getting ratepayers basically off the hook for coal plants that aren’t retiring, that might still be economic to run for a small number of hours,” Ammann said. 

Grid operators like MISO may have the most important role to play in better managing markets, refusing to dispatch coal plants that aren’t necessary and doing deeper analysis to figure out exactly how much power is needed. Experts say multi-day markets – rather than just real-time and day-ahead ones – could better match supply with demand and avoid unnecessary coal plant dispatch. 

MISO’s Independent Market Monitor has recommended such measures, including de-committing coal power producers who sold into the day-ahead market if it turns out that others – including renewables – could sell power more efficiently in the real-time market once the time comes. 

“MISO works closely with our members, state regulators and our independent market monitor to ensure our markets are efficient,” said MISO spokesperson Brandon Morris. MISO’s June 2024 monthly operations report shows that in June, 18% of coal-fired power dispatched in the region was uneconomic self-committed dispatch. 

Experts note that fuel delivery contracts often include a minimum purchase, so utilities committed to buying a certain amount of fuel might as well burn the fuel even if they are not making a profit on the power. This might not have been an issue in years past when coal plants operated at high capacity most of the time, but as coal plants have become increasingly uncompetitive, the NRDC study notes, they are more likely to be committed to buy fuel they actually don’t need. Fuel contracts are usually of short duration, with 88% of those reviewed by the federal Energy Information Administration expiring by 2025, meaning there is ample opportunity for fuel delivery contracts to be revised, the NRDC study said. 

Such fuel contracts have meant massive stocks of unneeded coal piling up at Duke plants in Indiana, Inskeep said, forcing the company to burn it even if the power isn’t needed.

Protogere said the coal supplies are necessary, as “the goal is to ensure a reliable supply in an increasingly uncertain market. The aim is to manage volatility as well as maintain long-term supply reliability and security, so that we don’t have to resort to higher cost options in the market.”

Inskeep hopes state regulators deny requests by Duke and other utilities to increase coal-fired generation and the recouping of the costs from ratepayers. 

“The bottom line with this uneconomic dispatch situation is it means utilities are keeping their old expensive coal plants open longer than they should,” Inskeep said. “Utilities should be rapidly transitioning to a renewable energy-based portfolio of resources. Instead, utilities are feeling pressure to justify a lot of the bad economic decisions they’ve made in the past, foolish decisions to invest millions or even billions of dollars to keep these plants open.”


Kari Lydersen wrote this article for Energy News Network.


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Residents in Nicholas and Clay counties could soon receive their electricity from a local solar plant, estimated to power around 90,000 homes in the region.

The Public Service Commission of West Virginia recently approved construction of the plant. According to a June 2024 survey from the Pew Research Center, one-third of respondents said a nearby solar development would help their local economy.

Gary Zuckett, executive director of the West Virginia Citizen Action Group, described the move as a win for the state and for the environment.

"West Virginia still generates about 89% of its electricity by burning fossil fuels, so any kind of new renewable energy is good news," Zuckett asserted. "We have a lot of policymakers in the state that sort of lean into fossil energy as the only way to generate power."

Deep Lake Energy Center filed an application earlier this year to construct a 150-megawatt solar electric generating plant on a former surface mine. According to the Commission, the company, a subsidiary of Shell New Energies U.S., estimated its capital investment would total $386 million and produce more than 300 jobs during construction.

Zuckett added skyrocketing utility bills are a consequence of continued reliance on fossil fuels, adding coal-fired plants are an expensive way to produce electricity, second only to nuclear power. He pointed out West Virginia residents energy costs have doubled over the past decade and major regional utility companies like Appalachian Power are proposing more hikes, prompting a rally in downtown Charleston this week.

"We are having a rally to demonstrate our discontent with the ever rising electric rates here in the state of West Virginia," Zuckett explained.

Research shows West Virginians' average monthly residential bills more than doubled between 2002 and 2022, from about $67 to $142 per month.


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Recent investments in clean energy from the Biden administration are hitting the ground in Wyoming. Engineering company TerraPower, founded by Bill Gates, recently broke ground in Kemmerer on what the company calls a "next-gen" nuclear reactor that it says will create energy more efficiently and safely.

The company aims to have the $4 billion project operational by 2030. TerraPower's project and others are getting federal boosts from the 2021 Bipartisan Infrastructure Law and 2022 Inflation Reduction Act, which provide billions of dollars for clean-energy projects through grants, loans and other incentives.

Shannon Heyck-Williams, associate vice president, climate and energy with the National Wildlife Federation, said Wyoming is slated to receive a good chunk of that funding.

"In Wyoming, $3.5 billion in private sector commitments and $4.1 billion in public investments in clean energy, infrastructure and manufacturing have all happened largely due to the passage of these two big pieces of legislation," she explained.

The U.S. Department of Energy is funding part of TerraPower's project to the tune of $2 billion. The laws also provide for projects at community and home scales, including investments in electric vehicles and charging stations, electric school buses and credits for homeowners transitioning to clean energy.

TerraPower estimates the project will generate enough power for up to 400,000, while creating 1,600 construction jobs and 250 careers. That's critical for communities such as Kemmerer.

"Every time a new manufacturing facility is created or retooled, that means new jobs for people, especially important in certain areas of the country that maybe have a declining economy related to fossil fuels or other sorts of older manufacturing," Heyck-Williams said.

The construction site is near a coal-fired electricity plant owned by Pacificorp and slated for retirement in 2036, according to the company's 2023 plans.

American Clean Power Week runs through Friday and a planned project for the North Dakota region, to open up more space on the electric grid, is gaining steam thanks to a new federal grant.

This month, the Department of Energy awarded up to $700 million to those helping oversee the North Plains Connector, a proposed transmission line covering parts of North Dakota and Montana.

Officials said the moves are needed to ensure grid reliability and affordable energy for consumers as the nation transitions away from fossil fuels.

Waylon Brown, regional policy manager for the Clean Grid Alliance, said the new line would accept all kinds of energy sources, including wind.

"As industry demand for electricity continues to grow, it's going to be extremely important that we continue to modernize our grid as a whole," Brown explained.

The demand he referred to includes data centers surfacing around the country, noting having enough available energy can attract such development in local communities. Transmission projects do take several years to complete, with permitting and other factors at play. Brown acknowledged clean energy advocates also need to get more community buy-in for renewables as grid space expands.

Kevin Pranis, Minnesota and North Dakota marketing manager for the Laborers' International Union of North America, predicted the project would create several hundred construction jobs. He also said if additional grid space breaks up the logjam of wind farm development, North Dakota communities could see a wave of jobs installing more wind turbines down the road.

"The renewable industry is creating good local jobs," Pranis pointed out. "That's certainly true in Minnesota. We've seen a lot of progress there in terms of both high-quality family supporting jobs and also jobs available to local workers."

Pranis noted unions like his are trying to convince companies in charge of renewable-energy development to not lean on out-of-state installers. In a coal-heavy state such as North Dakota, he argued it is important if more workers at those facilities need career transitions in the future. North Dakota still has several coal plants operating but it also has the fourth-highest share of wind power for any state.