PJM’s predicament
PJM Interconnection’s most recent capacity auction moved money like a Princess Diana bear at the height of the Beanie Baby craze. The July 30 auction produced a price of $269.92/MW-day for most of PJM’s 13-state footprint, compared to $28.92/MW-day for the 2024/2025 auction, a nearly 900% increase. The total capacity bill for the region grew from $2.4 billion to about $14.7 billion.
Ratepayers in PJM territory will start seeing the trickle-down effect on their respective bills beginning in mid-2025, which will surely delight those who don’t dutifully follow power market auctions.
PJM blamed the high prices on load growth, decreased supply offers due to coal generator retirements, and FERC-approved market reforms.
“We are recognizing unprecedented load growth consistent with load centers, like AI and data centers, and we are seeing pretty accelerated generator retirements,” PJM’s Donnie Bielak testified at FERC’s Innovations and Efficiencies in Generator Interconnection workshop earlier this month.
PJM anticipates at least 40,000 MW of load growth by 2039 and expects to lose at least 40,000 MW of fossil fuel generation by 2030. On paper, the numbers don’t look good, but as industry trade groups and politicians quickly pointed out, this situation was foreseeable and preventable.
The clean energy projects waiting in PJM’s interconnection queue right now have enough capacity to replace all the generation currently operating in the PJM system, even after planned fossil fuel plant retirements, but its overloaded queue is completely shut down until sometime next year. Advocates point out PJM has fallen behind on transmission planning and argue the RTO hasn’t adequately prepared for the grid of the future, damning ratepayers to bear the consequences.
“It is unacceptable that Maryland households and businesses will have to pay more because of our grid operator’s failure to get energy projects connected to the power grid in a timely manner,” read part of a joint statement released by Maryland State Senator Ron Watson and five state delegates.
Wind and solar make up a minuscule portion of the RTO’s current generation mix, whereas renewables make up nearly all of PJM’s interconnection queue, which is paused amidst a “transition period” from its serial study method to a new cluster-based approach.
“PJM is going to look to evaluate approximately 170,000 megawatts of queue projects that are almost exclusively renewables through this transition period,” PJM’s Bielak says.
Until the queue gets sorted out, PJM is in a pickle.
But like flowers wriggling up through cracks in the concrete, opportunities abound for distributed energy resources (DERs) to reduce grid stress and maybe make some money in the process. Could PJM’s problems turn it into a virtual power plant (VPP) powerhouse?
Home is where Heart is
Amy Heart is the senior vice president of public policy at Sunrun, which owns the second-most solar assets in the United States and is the largest provider of home solar and batteries.
“Every year we install the equivalent of a nuke plant,” she boasts with a smile.
Heart says PJM’s power auction reinforces the need to tap into every resource possible to keep bills as low as possible while staving off calls to conserve energy. Residential solar provides some grid relief, but the more valuable asset is paired storage, which is becoming more prevalent as battery prices decrease.
“Over half of our systems going in have batteries attached, and that’s dispatchable power,” Heart contends. “That’s now the equivalent of peaking power plants, out in homes across the grid, that can be used.”
That power can be used, but only in certain ways. Right now, that “dispatchable power” Heart references isn’t as dispatchable as it could be, but she sees hope on the horizon.
Allowing DERs to participate in the energy market
As Renewable Energy World contributor Rao Konidena explains like a pro, PJM initially tried to argue in its FERC Order 2222 proposal that multi-nodal DER aggregation is infeasible, limiting the way behind-the-meter resources can be used to support the grid. Then when FERC persisted, PJM proposed a way to allow for such aggregation, but only in a limited capacity.
“DER providers are unhappy with these restrictions because California ISO (CAISO) has shown that multi-nodal aggregation is possible,” wrote Konidena, referencing CAISO’s Load Aggregation Point (LAP) model. New York ISO (NYISO) also allows multi-nodal aggregation by specifying transmission nodes where aggregations are possible without restriction.”
PJM does allow zonal aggregation in capacity and ancillary services markets, but not the energy market. PJM currently restricts net metered customers from participating in energy or capacity markets, only allowing injections into the ancillary services markets.
Does this feel messy to you yet?
Sunrun’s Heart believes Order 2222 was “broken before it had a chance to get off the ground.” Seemingly arbitrary barriers to participation and delays in rulemaking don’t slow the need for electrons, she contests.
“State regulators and leaders have the opportunity and responsibility to fix the mess by requiring utilities to implement retail virtual power plant programs,” she implores.
“I still think after all these years, there’s some lack of understanding about how DERs operate and what regulatory structures and rules need to be in place to properly value the resource and incent the resource to deliver what it can,” notices Matthew Plante, president of virtual power plant operator Voltus.
GO DEEPER: Hype aside, virtual power plants are breaking through
Voltus has about a gigawatt of assets under management in PJM. Like Sunrun’s Heart, Plante recognizes an unprecedented incentive to maximize the capacity of existing resources, including flexible commercial and industrial loads and behind-the-meter DERs.
“We see ourselves as partners with the grid operators, finding ways to leverage all of these resources to benefit the grid, wherever they may be, wherever they may be suited, and whenever they’re needed,” Plante put it.
He believes most technological barriers to widespread VPP adoption have been erased, and only regulatory hurdles remain. If RTOs, utilities, and legislators can get on the same page, DER aggregation is a readily available means of bringing lasting relief to PJM.
“I don’t want to paint too doomsday a picture,” Voltus’s Plante offers. “We operate with residential VPPs across PJM now, we could just do more if every utility territory looked like ComEd’s, for example.”
VPPs to watch
Plante isn’t pulling ComEd out of a hat; the Illinois utility is working on a virtual power plant program to capitalize on the state’s performance-based rate-making policy, which compensates utilities based on how they’re using DERs to reduce peak load.
“While ComEd doesn’t have an official VPP program, ComEd does have rate programs and cost allocation programs that allow solar systems with and without storage to take advantage of hourly and capacity price signals to provide maximum value to the owner of the system, just as large power plants on ComEd’s grid do every day,” detailed Scott Vogt, ComEd’s vice president of strategy and energy policy.
“We look forward to working with the Commission and parties on this question,” he added.
Advocates have proposed something similar to ConnectedSolutions, National Grid’s VPP program in Massachusetts.
“We’ll see where the proposal lands with the Commission,” Heart says of the Illinois program, which should be figured out by the end of the year. “There’s also legislation that’s currently active that would require a program like this, so that’s kind of running at the same time.”
CPower and EnergyHub launched a new residential VPP partnership earlier this year for more than one million Ameren Illinois customers in MISO territory, utilizing DERs to help the grid operator manage demand.
Heart also recommends keeping an eye on Maryland’s DRIVE act, which is directing the Commission to create a ConnectedSolutions-type VPP program there, too.
ConnectedSolutions expanded from National Grid’s traditional smart thermostat program, “putting it on steroids” by utilizing storage to inject needed electrons into the grid.
“It is reducing load at specific times when it’s going to be most expensive to get that electricity from the wholesale market,” Sunrun’s Heart says. “And that is having real results. It has robust uptake, enrolling homeowners that have solar and battery programs.”
“That program’s been in place for several years now, and has become a really good model for what states can do,” she noted.
The Lone Star example
“PJM needs to look to Texas,” recommends Voltus’s Plante, who says the state deserves credit for figuring out how to manage a huge jump in peak demand.
After Winter Storm Uri, the grid operator took steps to prevent a similar disaster, including winterizing its natural gas and diversifying its energy mix.
“Texas has diversified away from just (natural gas and wind) partly by increasing the budget for distributed energy resources,” explains Plante. “That combined with a shorter queue in figuring out how to bring generation online, I think we can hopefully take some lessons from ERCOT.”
ERCOT’s “connect and manage” approach to utility-scale interconnection has proven efficient at getting projects onto the grid, often in less than a year.
Two years ago, ERCOT created the Aggregate Distributed Energy Resource (ADER) Pilot Project, which was established through the Public Utility Commission of Texas to evaluate the participation of ADERs in the ERCOT wholesale market. Sunrun’s Heart served on the DER task force, which helped identify the immediate barriers to an aggregated DER pilot.
“Knowing it’s not going to be perfect, but we’re going to get started so we can figure out the issues,” Heart acknowledged. In less than nine months, it was up and running.
Indeed, ERCOT’s model is far from perfect, Heart points out, but it allowed Texas to power through peak demand this summer without issuing calls to conserve. That’s a major win not only for ERCOT, but for people who didn’t have to sweat the prospects of losing power.
Clearly, aggregated DER programs can be a boon for grid operators, but it’ll be tough to sign people up at scale unless they’re properly incentivized.
Making Markets
Voltus sees PJM’s sky-high generation and transmission prices as an incentive to encourage more asset-backed demand response resources. Plante points out the highest penetration of behind-the-meter battery storage is in Ontario, Canada, and in California.
“The reasons for that are financial,” he explains. “Ontario has the Global Adjustment construct in place, which is the highest demand charge that I know of, at nearly $500,000 per megawatt per year for your peak demand. And California has demand charges right now of something like $64,000 per megawatt per month across the summer months. Those are the two highest demand charges and they have allowed folks to invest in behind-the-meter battery storage so that they can use those assets to offset their peak demand charges.”
Plante says PJM and MISO haven’t seen this gold rush for behind-the-meter storage yet because prices weren’t high enough to justify the upfront investment and batteries have been too expensive. But as capacity and demand charges have gone up, the cost of making batteries has gone down.
“You’re probably going to have a scenario where most other places in the U.S. look like California and Ontario,” predicts Plante. “Which is to say that there’s a lot more battery penetration, and we’re seeing that with our customers. Our customers have come to us to ask for battery storage solutions and we’re now able to help them finance those via either savings on their bill or by direct revenue from markets with these higher prices.”
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Supply and demand (response)
Once again, I defer to contributor Rao Konidena, who explains it excellently- PJM offered surprisingly little demand response capacity in July’s auction, just 8 GW. Plante contends there should be about 10% of a system’s peak enrolled in a demand response program, which would mean about 15 GW for PJM. FERC approved new rules in February that tightened rules around capacity accreditation following Winter Storm Elliott, which is a good thing if you ask Plante, who expects PJM to be back to 14-15 GW of distributed energy resources by 2027.
“You probably have a more reliable, solid base than in the past,” Plante contends. “I think in the past, those 14,000 megawatts had some real constraints in terms of ability to add value to the grid. The customers that are still in it actually have the ability to deliver more value to the grid than they’re being asked to do, so PJM’s program is still very much a last line of defense program, whereas many of the programs in a lot of other markets have evolved and call upon resources to do more than simply keep the lights on If we’ve exhausted all other options.”
This is where behind-the-meter batteries can shine. If aggregated properly, there should be considerable financial opportunity for those DERs to deliver real value to the grid.
“That’s where we have an opportunity to continue to move this market toward,” urges Plante.
A long December? The next PJM auction
PJM’s next power market auction is scheduled for December, a quick turnaround forced by the aforementioned capacity accreditation rules changes. Will prices be even higher come Christmastime?
“There’s probably some smart Warren Buffett quote about paying attention to long-term trends,” jokes Voltus’s Plante. “Last year, we were at our all-time lows there, there’s nowhere to go but up. This year, we’re at our all-time highs. I don’t expect to set an all-time high in December. I also don’t expect to go back to the all-time lows, as there’s not enough time between the auction that just cleared and December 2024 to really change the fundamentals.”
“This is supply and demand,” he continued. “We are in a load growth environment for the first time in a while. The interconnection queue is real, and the retirement of coal plants is real. The fundamentals have changed.”
In his testimony at the FERC workshop, PJM’s Bielak seemed to indicate there wouldn’t be another surprise at the end of the year.
“The resource adequacy issues we may potentially be seeing in future years (are) already being reflected in our market prices and our market signals,” he said.
When Plante peers into his crystal ball, he sees prices in PJM territory around 80% of what they settled on in July.
“Setting up markets for DER aggregation is not without its challenges, and PJM’s approach hasn’t always produced their desired outcomes,” admits Plante. “So we have a lot of work to do with regulators to help them understand how they can structure things to drive the outcome they want- which is affordable, reliable electricity for everybody.”
Sunrun and its bevy of dispatchable behind-the-meter batteries will be standing by.
“We’re ready to work with utilities to dispatch that when needed, and make sure the customers get compensated for that as well,” confirms Heart. She sees DER aggregation as a logical way to smooth out PJM’s pricing problems but recognizes they’re only a piece of the whole picture.
“There is not a silver bullet solution,” she opines. “We cannot say, oh, we need more transmission lines. Oh, we need to build more generation, and then we’ve got it. What do you do in the next 10 years as you’re trying to figure out transmission? What do you do in the next five years? What do you do in the next season? That’s where we are really well suited to not only fill the gap with the increasing demand, but also fill the gap at specific times, at peak load times, when the grid needs it the most.”
