As concerns about the costs of electricity rise, utilities, regulators, and consumers are looking into what’s putting upward pressure on prices — and what can be done to mitigate this pressure.
For utilities and customers in areas served by regional transmission organizations with capacity markets, a recent spike in capacity costs has been a major driver of increases. PJM Interconnection saw prices jump 830% in 2024 auctions and 22% in 2025. A temporary price cap of $333.44 per megawatt per day was set in the PJM market in 2025 following an agreement with the state of Pennsylvania. ISO-New England’s 2024 jump in the forward capacity auction was around 38%. The Midcontinent Independent System Operator's summer auction rate rose from about $30 per megawatt per day in 2024 to $666 per megawatt per day in 2025.
Each of these RTOs is examining and implementing changes to its capacity markets. For public power providers within PJM, MISO, and ISO-NE, technology, partnerships, and agility could all come into play to secure the power supply they need while keeping an eye on costs.
Rethinking Value
As with many issues in the power sector, a confluence of forces is driving the surge in capacity market prices.
“The resource transition itself is one driver of change in capacity markets,” said Rao Konidena, president Rakon Energy, a consulting company. “A lot of coal plants are retiring at the same time a lot of renewables are coming online.”
“You can’t compensate a 20-megawatt gas plant and a 20-MW wind farm the same way,” said Dave Meisinger, CEO of the Connecticut Municipal Electric Energy Cooperative, which provides power and services to six public power providers in the Constitution State. “These resources are just not going to be operating the same way. The gas plant’s going to operate more frequently and run on a more predictable timeline. You have to find ways to account for that.”
Several markets have done just that, and most are compensating generators based on accredited capacity, which better reflects capacity’s actual value. For example, a gas plant would receive a capacity value close to its nameplate capacity because it’s dispatchable at will.
“If you build a 100-MW gas plant, you typically get 90 MW of accredited capacity. With renewable resources, their contribution to capacity is about 30%,” explained Patrick Bowland, CEO and general manager of the Michigan Public Power Agency. He added that 100 MW of solar delivers 50 MW or less of accredited capacity, while 100 MW of wind only delivers 15 MW. “That’s one reason reserve margins started to decline.”
Considering Co-Location
Another cost driver is the extended timeline for interconnection. “Historically, when somebody would interconnect a new resource, it would be a big plant: 500 MW or 1,000 MW,” Bowland continued. “When you’re interconnecting smaller renewable projects that are 25, 50, or 100 MW, it takes dozens and dozens of plants to equal the same capacity.”
This dynamic amplified the number of interconnection requests over the past several years, creating what Bowland called “gigantic backlogs to interconnect resources to the transmission grid.” He added that it used to take about two years from filing an interconnection application to obtain an interconnection agreement. It now can take four to five years.
This is one reason MPPA is looking at surplus interconnection. “If we have a power supply resource with an existing interconnection, evaluating the economics of locating another power supply resource behind the same meter is an important due diligence step, particularly for renewable resources like wind and solar,” Bowland said. “It could be a battery or gas project, but it’s using the same point of interconnection. The power it produces is going to the same meter the wind or solar is using.”
“The transmission interconnection has to be much faster,” Konidena said, adding that it can take as much as 10 years to build new lines.
A similar solution to interconnection delays is the co-location of load and generation at the same site. “If you have a load interconnection request and a generator interconnection request, they’ll take two or three years sequentially — that means six years,” Konidena said. “A co-location request can be studied in one instance.”
The argument for co-location is that it enables data centers to access power more quickly while saving utilities time and money by eliminating transmission builds. In December, the Federal Energy Regulatory Commission ordered PJM “to establish transparent rules to facilitate service of [artificial intelligence]-driven data centers and other large loads co-located with generating facilities.” This type of market reform could help power providers keep rate impacts down and still meet capacity requirements.
Shorter Cycles
Weather is yet another driver of price fluctuations. Konidena pointed out that storms — such as the major winter storm in December 2022 that affected PJM territory — can disrupt supply chains and asset performance. “If a gas pipeline freezes, the market operator can’t rely on its gas plants,” he said. “The capacity grid operators thought would be online during the storm can quit performing, and that’s also driving the change in capacity markets.”
Among those changes are tighter timelines. In New England, annual capacity auctions occur approximately three years before the annual capacity commitment period to which they relate. Meisinger mentioned proposed changes in the ISO-NE markets on timing and seasonality. “Instead of three years in advance, it will be a month or so before the period and thus a ‘prompt’ market. They’re also proposing to divide it into seasonal markets because generation resources operate differently based on weather, and you also have different levels of demand in the winter versus the summer,” he added. This more frequent auction schedule is proposed to take effect in the 2028–2029 capacity period.
This change is going to shorten planning timelines, but that’s happening coast to coast. “The planning horizon has shrunk because technology and political changes have accelerated so much that you can’t plan the way you used to,” Bowland said. “You have to be much more agile.”
In his consulting, Konidena has observed some public power utilities still using three- or four-year planning cycles for their resources. He said most public power providers should now consider integrated resource plans on a one- to two-year horizon because of the rapid changes affecting capacity needs and prices.
New Strategies
Konidena believes utilities with transmission should embrace grid-enhancing technologies to combat high capacity costs. “Basically, these technologies allow you to get more throughput out of the existing system, free up capacity, and interconnect more resources,” he explained.
Among these technologies are sensors combined with analytics that factor in line temperatures, wind speeds, weather forecasts, and historical data to help grid operators increase or decrease the power flowing on transmission lines.
Getting more from existing assets is part of MPPA’s multipronged strategy to deal with today’s capacity markets. “The best way to describe it is that we’re trying to extract as much value as we can from assets we own, control, or manage, whether these are located within our member communities at the distribution level or connected to the transmission grid,” Bowland said. This includes “repowering,” which means the organization is no longer going to burn coal — it has state legislative mandates to meet — but it will continue to burn gas. “We’re reducing our carbon footprint while maintaining the same level of capacity instead of retiring a plant.”
In Connecticut, Meisinger said capacity isn’t the biggest headache that his joint action agency’s members see on their monthly invoice, but it could be. “It’s creating the desire to find new strategies,” he added, “and there’s one in particular that is theoretically out there but not as many parties take advantage of it.”
He’s talking about bilateral transactions. “Rather than wait around to see what the capacity price is going to be when you really have no option but to take that price and pay it, we’re looking for counterparties who might own resources and can sell us capacity. We can negotiate a longer-term deal and fix the price,” Meisinger explained. The agency already employes a hedging strategy for most of its energy portfolio, Meisinger added.
Another thing public power providers can and should leverage is load itself. MPPA is exploring a partnership with an aggregator to provide the software and expertise for demand response programs serving both residential and commercial-industrial customers. “Our interests are about resource adequacy,” Bowland said. “We want to be able to reduce our peak load so that we can reduce the capacity obligation that we have. It made sense for us to do this through a partnership with people who have already cut their teeth in that space.”
Konidena also counsels utilities to consider demand response to address capacity issues, but he warns change is headed to that world, too. “Market monitors are focused on demand response not performing as expected, and they’re tightening the rules at the same time when we need more demand response on the grid to reduce consumer prices,” he said.
Specifically, monitors of PJM and MISO are looking at holding market participants responsible for the performance of individual loads within the aggregator’s collective response. Monitors would also like to see loads curtailed for four continuous hours, not coming and going at will. If these changes occur, they could drive some curtailment participants and market players out of the markets, so it’s something to watch.
But don’t just watch, said Meisinger. Get involved.
“It’s a hallmark of public power to participate in regulatory processes and advocate for what we need both individually and collectively as part of the public power community,” he said. “We do a lot of that advocacy jointly with the other joint action agencies here in New England, with our regional public power trade association, and with [the American Public Power Association]. We do have a voice. It’s part of the value proposition that we bring to our members and ultimate ratepayers.”
