Zombie coal plants could threaten the US energy transition

On the banks of Maryland’s Patapsco River, about 10 miles south of Baltimore, there’s an aging coal plant that pretty much everyone wants to shut down. Local community activists, environmental groups, state officials, even the company that owns the coal-burning facility — they all want to close the Brandon Shores Power Plant next year.

But they can’t.

Think of Brandon Shores as a zombie coal plant: a polluting and money-losing facility that’s being kept alive due to a lack of foresight from grid planners and an outdated set of energy market and policy regimes that have made it nearly impossible to replace the plant with cheaper and cleaner alternatives.

The facility, which groups have been trying to shut down for years, now faces the prospect of being kept open at the expense of Maryland utility customers until at least 2028 — and potentially even longer. Efforts to replace it with a massive grid battery and targeted grid upgrades, which advocates say can be done quickly and at a comparatively low cost, have also been shot down.

Unless utilities, regional grid organizations, state regulators, and clean-power advocates can correct these problems, the 1,278-megawatt coal plant could foreshadow much broader threats to the prospect of cleaning up the mid-Atlantic region’s power grid.

“It’s become the poster child for what can happen — for what can go wrong — if we fail to plan effectively for the energy transition,” said Katie Siegner, a manager with RMI’s Carbon-Free Electricity team. (Canary Media is an independent affiliate of RMI.)

“In the coming years, we could see a lot more Brandon Shores,” she said. “Or we could see it as a wake-up call to pursue alternative solutions.”

The Kafkaesque rules keeping zombie coal plants alive

At the heart of the Brandon Shores impasse is a set of Catch-22s in how PJM, the grid operator responsible for energy markets and grid planning across a 13-state region including Maryland, manages the prospect of potential power plant closures.

PJM is one of the most coal-heavy grids in the U.S., and coal plants — the dirtiest way to generate electricity — are in decline across the country. That’s partly due to state clean-energy goals like those in Maryland, which has a plan to achieve 100 percent clean energy by 2035, and where the last of the state’s eight coal plants were set to shutter by next year. But an even bigger driver is that coal plants can’t compete economically with cheap fossil gas and renewable energy.

All told, out of its current 185 gigawatts of generation, PJM can expect 43 to 58 gigawatts of mostly fossil-fueled power plants to close by 2030, according to a March report from its independent market monitor. Nearly 20 gigawatts are expected to close for regulatory reasons, and another 19 to nearly 34 gigawatts are expected to close because of financial pressures.

Keeping power grids reliable requires aligning the economic incentives to build power plants and grid infrastructure with what physics dictates is needed to withstand the worst-case scenarios. Those include the energy demand peaks that arise during summer heat waves and winter storms. They also include contingencies like power plants being forced offline unexpectedly, or power lines being taken out by storm damage or equipment failure, which can put regional grids in peril of collapsing.

But PJM hasn’t planned ahead to build the grid required to enable clean energy to replace the coal-fired power that’s set to shut down, advocates say. That lack of foresight has helped mire hundreds of gigawatts of solar, wind, and battery projects in yearslong grid-interconnection backlogs, preventing them from plugging into the grid fast enough to help mitigate fossil-fueled power plant retirements. It’s a nationwide problem that’s particularly acute in the PJM region.

The result is that when coal plants do announce plans to retire, PJM grid reliability planners are left scrambling, said Mike Jacobs, senior energy analyst for the Union of Concerned Scientists.

“There’s no action until the plant owner announces they’re going to close,” he said. “PJM must do an analysis in something like 60 days or 90 days to determine if there are impacts from those closings and then come forward with solutions to those impacts.”

Grid operators have a prescribed set of options to deal with any reliability problems a closure might cause. The first is to fast-track big new transmission projects, even if they won’t be completed for many years to come. The second is to engage in a “reliability must-run” (RMR) negotiation with power plant owners — essentially, paying power plants otherwise headed for the graveyard to stay alive in the event they’re needed in an emergency.

The situation with Brandon Shores

That’s what’s happening now with Brandon Shores and the nearby H.A. Wagner Generating Station. Talen Energy, which owns both power plants, pledged in 2020 to either convert its coal plants to cleaner fuels or shut them down by 2025, after a long-fought effort from community activists and the Sierra Club.

“We’ve been working with Talen for years to do this, in coordination with a local community that's affected by the plant,” said Casey Roberts, senior attorney with the Sierra Club's Environmental Law Program.

But after Talen Energy told PJM in April 2023 that it intended to shut down its two coal-fired units at Brandon Shores in 2025 rather than refit them to burn oil — one of the other options it had proposed back in 2020 — PJM found that those closures would cause unacceptable grid reliability risks.

To forestall these risks, PJM in June proposed an RMR for Brandon Shores until a $780 million series of grid upgrades can be completed in 2028. Earlier this year, PJM launched an RMR process for the H.A. Wagner Generating Station as well, after Talen told the grid operator in October that it planned to close down the site’s oil- and fossil-gas-fired units.

This approach comes at significant cost. The Brandon Shores RMR contract could cost up to $250 million per year, or potentially $1 billion over the next four years, in “out-of-market” payments, according to estimates based on its initial contract with PJM.

And these RMR contracts may last well beyond 2028. There’s no guarantee that the transmission grid upgrades meant to solve the problems will be finished in time, given how hard it is to complete such projects across the country.

To add insult to injury for policymakers and ratepayers in Maryland — a state with aggressive clean energy goals — RMR costs are borne by ratepayers living in the state where the power plants are located. They’re not spread out across PJM members, as is the case with broader regional grid expansions.

“If they would plan ahead, they could competitively procure, and save customers tens or hundreds of millions of dollars,” David Lapp, who leads Maryland’s Office of People’s Counsel, the independent agency that advocates for residential utility consumers, told Canary Media.

But instead, as Lapp wrote in a September protest asking the Federal Energy Regulatory Commission (FERC) to reject PJM’s fast-tracked transmission plan, the grid operator’s “failure to plan” for the “entirely foreseeable” closure of Brandon Shores “is now being used as a rationale for solutions that benefit utility monopolies and unnecessarily impose high costs on the backs of captive customers.”

This piecemeal and reactive approach to dealing with power plant closures has become a top concern of regulators at the organization of states that make up PJM. In a November letter, the organization warned PJM of the “negative impact of siloed, reactive planning,” and the stopgap “Immediate Need” transmission projects and RMR interventions “that can cost customers hundreds of millions of dollars per year.”

PJM has pushed back on these complaints. “Whether the issue was solved three years ago or today, the substantial transmission upgrades identified by PJM to sustain reliability of the grid have to be made to keep power on for roughly half the state of Maryland,” the grid operator told FERC in its October response to Maryland and PJM states’ protests.

“PJM regards RMR arrangements as a last resort,” PJM spokesperson Jeffrey Shields said in an email. But the grid operator “could not have proactively planned for the Brandon Shores or Wagner retirements,” given that Talen had told the grid operator that it was going to convert the Brandon Shores units to burning oil in lieu of coal and obtained approvals from Maryland regulators to do so, he said.

But Lapp argued that PJM must do more to prepare for power plant closures before their owners explicitly announce them. The coal plants in Maryland are not “selling very many megawatt-hours,” he said, indicating an inability to earn money. Talen also went through a bankruptcy reorganization from 2022 to 2023, giving the company little headroom to undertake expensive power plant retrofits, he said.

Given these factors, “it was entirely predictable that Brandon Shores would retire,” he said.

A battery alternative, proposed and rejected

Clean energy advocates and Maryland officials have also been frustrated by the roadblocks to a set of proposed alternatives to the Brandon Shores RMR that backers say could be cleaner, cheaper, and more valuable in the long run.

In a January report commissioned by the Sierra Club, energy analysis firms GridLab and Telos Energy found that an 800-megawatt, four-hour battery, combined with transmission reconductoring and voltage-support projects, “would obviate the need for an RMR” at Brandon Shores and at a lower cost.

The combination of batteries and grid upgrades could be completed as early as the end of 2025, giving PJM more time to study and build appropriate regional grid upgrades, said Casey Baker, senior program manager at GridLab. And batteries could provide value for decades into the future, “whereas with an RMR, you pay that money, and the money’s gone,” he said.

Maryland has a state mandate to build 3 gigawatts of energy storage by 2033, with the first 750 megawatts required by the end of 2027. State officials have pressed PJM and FERC to consider the option of fast-tracking the procurement process to help deal with Brandon Shores.

PJM has rejected these alternative plans. Earlier this month, PJM told Maryland officials that the battery alternative “is not technically viable to resolve the reliability violations or avoid the need for an RMR agreement at this time.”

To be fair, the engineering challenges in ensuring a reliable grid aren’t simple to solve. PJM highlighted in its October filing with FERC that the Brandon Shores plant “provides certain physical attributes, such as inertia, that are necessary for electricity to get from point to point” in a region that is “simply lacking in bulk electric system infrastructure.”

Roberts of the Sierra Club questioned PJM’s dismissal, noting that it appears to have discounted the role of the additional grid reconductoring and voltage-support investments along with the batteries that GridLab and Telos Energy studied.

But she also highlighted another set of barriers that, unlike the laws of physics, could be addressed via policy changes — if PJM’s utility and state stakeholders can agree on what to do.

“Ultimately, to get this kind of thing to happen, you need a regulatory framework where PJM says, ‘We have a short-term reliability need until these transmission lines are completed. What’s the best way to meet this need?’” But for alternatives like using batteries instead of zombie coal plants, “right now, they don’t have any framework,” Roberts said.

Why it’s so hard to use new technologies to replace old ones

Getting that framework in place won’t be easy.

“I don’t know that any [regional grid operator] has done this thorough of a study looking at this mix of resources as an alternative,” Justin Vickers, a senior attorney for the Sierra Club's Environmental Law Program, said of the Grid Lab and Telos Energy study. “They're bound by what they know and what their tariffs explicitly state — that you can give out-of-market payments to coal plants to maintain reliability, or you can build transmission. And there’s not a lot of room for anything else.”

One big problem is that PJM lacks a structure to allow batteries to be considered as a transmission asset, he said. Other countries, including Australia and Germany, have successfully deployed large-scale batteries to store energy at either end of a transmission line to cover potential shortfalls during the rare instances when those lines can’t handle the power flows demanded of them. That can be a lot faster and less expensive than upgrading those power lines or building new ones.

FERC has clarified that energy storage can be used as a transmission asset, and U.S. grid operators in the Midwest and Northeast are exploring how to do that, Vickers said. But PJM’s effort to create a process for allowing batteries in lieu of transmission has not moved forward over the past four years, he said.

Shields, the PJM spokesperson, said the grid operator’s Members Committee, which consists of 501 voting members including utilities, power plant owners, transmission owners, major customers, and energy traders, “voted not to proceed with the endorsed package” that emerged from that effort. PJM expects to revisit the issue later this year, he added.

“The thing that in the U.S. is currently holding them back in many instances is this concern about how to use them as both market and transmission assets,” Vickers said. “There are a bunch of reasons why that’s complicated,” largely tied to the hard line U.S. grid operators draw between how transmission projects and power plants earn money.

Batteries could store energy to relieve transmission lines when that’s needed, and earn market revenues during other times. That could be a more cost-effective way to handle multiple grid tasks, compared with single-purpose technologies — but only if batteries are allowed to earn money for doing those different things.

PJM and other U.S. grid operators allow coal and gas generators to simultaneously provide transmission reliability services and collect energy market revenues. But paradoxically, PJM rules do not allow storage to do both, GridLab’s Baker said. Developers have to pick one use case or the other.

Unfortunately, the battery project that GridLab and Telos Energy studied for replacing the Brandon Shores RMR is cost-effective only if it can do both, Baker said. “There’s not a pathway for this project to simultaneously fix the grid problems and also collect the market revenues of a storage project — and that is a barrier.”

Swapping retiring power plants for new ones is not easy

Finally, there’s a chicken-and-egg problem for a battery project, or any other resource, seeking to fill the grid hole that closing Brandon Shores would create, said Lapp of the Office of People’s Counsel. That problem is tied to the capacity interconnection rights (CIRs) that any grid resource must hold to compete to earn money in PJM’s capacity market, which pays power plants and other resources for being available to meet future peaks in grid demand.

Capacity market payments can make up a significant slice of the total value for generation assets on the regional grid. It’s hard to finance and build a project without them. But each subregion of PJM’s grid has only so much room for capacity resources.

That’s an issue in the grid subregion that includes Brandon Shores, Lapp said. “There are 1,200 megawatts of capacity interconnection rights being applied for by developers,” he said. “But none of them have interconnection agreements” from PJM that would allow them to move on to the next steps of starting construction. Meanwhile, Talen retains Brandon Shores’ 1,278 megawatts of capacity interconnection rights, “which effectively acts as an entry barrier to other developers.”

RMI’s Siegner highlighted a potential workaround to that barrier: using the capacity interconnection rights of the closing power plant itself. In February, RMI published a report on the potential for “clean repowering” — using interconnection rights at fossil-fueled power plants to add solar, wind, batteries, and other zero-carbon resources to the grid. It found the approach could enable 250 gigawatts of renewable energy projects nationwide without requiring transmission upgrades.

But even this prospect is forestalled by PJM policies, Vickers said. Under PJM’s rules, “for a new storage asset to come online purely as a market participant, the same way the coal plant has been, would require the project to go back through the generator interconnection queue,” he said — and that queue is notoriously backlogged until at least 2026.

Other grid operators have different structures for how to transfer these interconnection rights from power plants that plan to close to replacement resources that could use them. GridLab highlighted some examples of where those structures have been successfully used in other grid regions in a report filed with PJM.

Siegner noted that a stakeholder process at PJM is exploring a “generator replacement” structure that could make it possible “to transfer CIRs from a retiring plant to a third-party developer, and have a fast track created to expedite the study of that new resource.” But the monthly discussions of this working group are “progressing pretty slowly,” she said.

Shields said this issue has been “regularly and thoroughly discussed since work began last July at the Interconnection Process Subcommittee,” where members are “considering changes” that “will give them the ability to effect comprehensive change.”

All in all, Siegner said she fears it may be too late to find solutions to the zombie fate of Brandon Shores, “because we’re now down to the wire.” Every year that Talen receives RMR payments for keeping its Brandon Shores and H.A. Wagner plants alive erodes the savings that any alternative solution could provide, putting its viability increasingly out of reach.

In that light, the best solution would have been for “PJM to proactively plan transmission,” she said — “although for Brandon Shores, that would involve turning back the clock about 10 years.”

How to build the grid needed to let polluting power plants close

What about the future prospects of proactive transmission planning? PJM is now taking steps to rectify its grid-planning approach to prepare for the likelihood of more coal-fired power plants being pushed to close in the years to come, whether by clean energy mandates or by energy market economics. But it remains a work in progress.

PJM’s current grid-planning processes don’t capture the changing mix of generation across its 13-state footprint, said Tom Rutigliano, senior advocate for climate and energy at the Natural Resources Defense Council. “They just take the status quo and extrapolate it out,” he said. That includes assuming that the current mix of power plants will remain static for the next five years, he said — an assumption that prevents it from planning for plant retirements even as clearly telegraphed as Brandon Shores’ had been.

Last year, PJM launched a long-term regional transmission planning initiative meant to look out 15 years and consider multiple future scenarios, including those in which new power plants are being brought online and existing ones are closing for public policy and economic reasons.

But according to Rutigliano, the latest iteration of PJM’s long-term plan still runs the risk of failing to capture the full range of retirements that its market monitor is forecasting will happen over the rest of the decade. PJM’s base-case scenario would limit inclusion of new solar, wind, and battery projects expected to be built to meet state clean energy mandates, he said. It would also fail to “take a realistic look at how many fossil fuel plants are going to retire over the next 15 years.”

Shields said that PJM is “currently considering” changes to its planning “that will enable PJM to get started with an enhanced long-term planning process, which is critical to support reliability into the future.” PJM members plan to vote on those changes in the weeks following FERC’s ruling, he said.

PJM has also highlighted that transmission capacity isn’t the only factor holding up the buildout of renewables. Nearly 40 gigawatts of generation projects, mostly renewables, have completed PJM’s study process and have not been built, due to financing, siting, or supply-chain issues unrelated to PJM’s process — an indication of the multiple challenges to expanding capacity to replace retiring power plants that lie outside the grid operator’s control.

PJM’s current proposal on grid planning is likely to undergo significant changes from its current form, however, Rutigliano noted. A Monday order from FERC will require the country’s grid operators, including PJM, to follow a common set of methods for how to structure long-term grid plans.

“Now that FERC’s order will come out first, PJM has a real opportunity,” he said. “By updating their plan to meet FERC’s new requirements, PJM can start comprehensive transmission planning as soon as this summer.”

PJM CEO Manu Asthana testified before Congress last year that the region faces a dual challenge of fossil-fueled power plants retiring and new resources not being brought online quickly enough to replace them. Given that risk, “it would be unacceptable for PJM to exclude the retirements they’re worrying about from their transmission planning,” Rutigliano said.

It’s not clear how many of the coal-fired power plants at risk of retiring in PJM in the coming years might require out-of-market interventions to forestall grid reliability risks. Not all power plants are in regions as grid-constrained as Maryland is, Lapp highlighted.

But without a grid planning regime designed to take long-term resource-mix changes into account — and without innovations in how to handle unexpected power plant retirements — it’s impossible to rule out the potential that Brandon Shores is not an outlier but a harbinger of far more zombie coal plants to come.

“We’re focused on what changes need to happen at PJM to prevent these kinds of things from happening in the future,” Vickers said. “No one else is in a position to do that but PJM.”