BALTIMORE — Getting storage online in Maryland could be a critical piece of the solutions needed to address the sky-high capacity prices PJM recorded in its most recent auction, according to a panelist at a solar and storage conference. 

“This is a hands-on-deck moment for Maryland to get these technologies on board,” said Joel Harrington, director of government affairs for REV Renewables, a solar, wind and storage developer. “Sitting in the PJM queue right now, just for transmission-connected storage, are 17 projects … [that] can come online in the next few years.” 

Totaling 1.6 GW, those projects represent only the queued-up storage that would be located in Maryland, Harrington said, and getting them online, while not a panacea for PJM’s capacity market problems, is essential. What state regulators, the industry and other stakeholders need to figure out is “what’s going to attract, what’s going to send appropriate price signals” to developers, he said. 

PJM capacity prices increased nearly tenfold in the 2025/26 Base Residual Auction in July, jumping to $269.92/MW-day, far above the $28.92/MW-day for the 2024/25 auction. Prices in some parts of Maryland and Virginia hit $466.35/MW-day and $444.26/MW-day, respectively. (See PJM Capacity Prices Spike 10-fold in 2025/26 Auction.) 

Harrington and other panelists at the Chesapeake Solar and Storage Association’s Solar Focus 2024 on Nov. 20 debated the options for accelerating deployment of residential and both distribution- and transmission-tied storage, as outlined in a recent report from a Maryland Public Service Commission “workgroup.” 

With the passage of H.B. 910 in 2023, Maryland set ambitious targets for getting new energy storage on its electric system — 750 MW by mid-2028; 1,500 MW by mid-2031 and 3,000 MW by mid-2034 — with the goal of creating a “robust and cost-effective” storage market in the state. 

The Maryland Energy Storage Initiative (MESI) Workgroup Phase 1 report is aimed at kick-starting the state market to hit the first 750-MW target. Plans for phases 2 and 3 will be developed in subsequent reports.  

The workgroup recommends a multipronged approach to market development with a potential mix of utility and third-party owned storage both behind and in front of the meter, including rooftop residential and distribution- and transmission-tied projects.  

In front of the meter, utilities might develop their own distribution- or transmission-tied storage or procure projects from third-party developers, the report says. The behind-the-meter market might get a boost from other state programs being developed under other laws, such as the Distributed Renewable Integration and Vehicle Electrification (DRIVE) Act (H.B. 1256), which promotes the aggregation of renewables and storage in virtual power plants. 

Another new law, H.B. 864, allows behind-the-meter energy storage to be integrated into utility demand response programs as part of a state energy conservation program. 

The report stresses the integral role of aggregation in market development, not only within but also across different programs and storage sectors.  

“While the financial, environmental and equity-related benefits and costs of individual storage deployments and programs should not be ignored, it is important to focus on designing an energy storage market that maximizes the aggregate value of all energy storage deployments and the entire portfolio of MESI programs for the grid, ratepayers and the state’s policy goals,” the report says. “Some benefits that storage can provide can only be realized through the aggregate behavior of many devices, and therefore these benefits can be difficult to measure at an individual project or program level.” 

Non-monetizable Benefits

The MESI Phase 1 report was submitted to the PSC on Oct. 1, kicking off a comment period that ended Nov. 7. The commission is reviewing the comments and will issue an order, though no time frame has been mentioned, according to an email from a PSC spokesperson.  

The panelists agreed that a core challenge for state regulators will be setting up market structures that allow storage projects to be fairly compensated for the full range of services they can provide to cut costs for consumers. 

The workgroup report recommends upfront incentives in some instances, which could be critical in the residential market, said Jamie Charles, manager for grid services policy at Sunnova, a residential developer.  

While cost savings are the main motivation for homeowners to install solar, “storage is really developed for resilience,” Charles said. “So, by providing these upfront incentives and providing these proposals for these grid services programs and these virtual power plant programs, that’s going to really reduce that barrier to entry.” 

The report sees either the Maryland Energy Administration or individual utilities setting and distributing such incentives, which could provide a “strong foundation” for the expansion of the residential storage market in Maryland, Charles said. 

Kavita Ravi, senior vice president at BlueWave Energy, a solar and storage developer of distribution-level projects, argued commercial projects should not have to pay demand charges that commercial generation projects typically pay.  

“There are several benefits that storage can provide that are non-monetizable, so it’s kind of an unfair market overall,” Ravi said. “In order to allow storage to take off in the electric distribution grid, we think it is important to not levy demand charges during charging.” 

Utility demand charges usually are based on specific times of highest demand; for example, when extra power is needed on cold winter days or hot summer afternoons. But for storage, demand charges often are based on the assumption that a project always will charge at its maximum capacity, which the industry has argued is not realistic. 

Ravi pointed to the concept of a “wholesale distribution tariff” being developed in the Northeast specifically for storage, which “will fairly apportion the transmission costs and then the charging costs as well, which is more thoughtful and fair for storage.” 

For transmission-tied storage, Harrington wants multiple options as well, including full- and partial-toll contracts and upfront incentives. A full-toll option “would be a power purchase agreement or long-term contract where you would contract for energy, ancillary services and capacity, so all three of the attributes would be a fixed price,” he said. 

A partial toll would be a fixed-price contract for capacity only, with developers free to bid into either energy or ancillary services markets.  

Balancing State and Local Control

Flexibility will be critical going forward, Harrington said. “Our markets [are] changing. The uncertainty around the [Inflation Reduction Act] is really making us question, how do we monetize these assets in the next four or five years? So, we need to be nimble.” 

All the different procurement and contract options will “attract energy storage at some level,” Harrington said. “Every business is going to have a different option as to which one is going to attract the best investment for their business.” 

The panel also talked about the need to streamline interconnection and for state standards on permitting and siting, while still allowing some flexibility for local control. 

While developers will continue to look for project sites that are “non-conflict prone,” Harrington called for “the state establishing specific standards, instead of this patchwork of a developer going into each community, each town [where} they have their own set of rules and ways of regulating and permitting projects. 

“The balance is being cognizant of local control, respectful of local control … but having siting standards, ordinance standards that communities can at least follow as a base,” he said.