Maryland utilities propose mix of transmission and distribution storage; commissioners press for clearer cost, siting and ratepayer protections

Exelon Maryland utilities and other investor-owned companies told the Maryland Public Service Commission (PSC) that utility-led procurements of energy storage could accelerate meeting the state's interim storage goal and provide stability for developers.

At a PSC proceeding (Case 9715) convened to implement the Maryland Energy Storage Program, utility witnesses proposed a mixed portfolio of transmission-connected and distribution-connected batteries, recommended contract structures they said reduce risk to customers, and asked the commission for guidance on budget and cost-recovery approaches ahead of more detailed program filings.

Those requests matter because the Maryland General Assembly has set an ultimate storage target of 3,000 megawatts by May 31, 2034 and an interim goal of 750 megawatts by 2028. The Next Generation Energy Act (identified in testimony as Senate Bill 937, cross-filed as House Bill 1035, and other related statutes referenced in the hearing) additionally directs the PSC to run procurements for transmission-connected storage and requires utilities to propose distribution-connected programs. How the PSC allocates costs and structures contracts will affect whether projects get financed and how quickly storage is deployed.

Exelon Maryland Utilities: portfolio, tolling and cost recovery

Representatives of Exelon Maryland Utilities (BGE, Pepco/Delmarva/PHI affiliates) outlined proposals that would include both large transmission-connected projects and distribution-connected storage. In their statement, Exelon outlined a concept of 600 megawatts of transmission-connected storage and 150 megawatts of distribution-connected storage as part of initial procurements to help reach the interim 750 megawatt goal. The utilities said they expect to pursue both third-party and utility ownership models.

Exelon and BGE witnesses emphasized contract design as a central policy choice. Their preferred commercial form for large, transmission-connected projects is a “full tolling” contract in which a utility pays a fixed price schedule to a storage developer and the developer retains and monetizes wholesale market revenues. Exelon argued that a full tolling structure reduces exposure to long-term wholesale price forecasts and therefore lowers risk to customers and the utility.

Bill Pino, Exelon’s director of energy acquisition, told commissioners that the full-tolling approach lets developers compete on construction efficiency and cost of capital instead of forcing them to forecast 15 years of PJM market revenue: "The full tolling agreement does not require the developer ... to be forecasting long‑term market prices," he said, explaining that the fixed schedule primarily covers construction, maintenance and the developer’s cost of capital.

By contrast, in a “partial tolling” structure the developer would price a portion of the contract based on forecasted market revenues (capacity, energy arbitrage, ancillary services), creating variable revenue exposure that Exelon said could raise financing costs and shift market forecast risk to customers.

Cost recovery and budgets

Utilities asked the PSC to authorize a regulatory-asset approach for recovery of program costs and to confirm treatment in future rate proceedings. Pepco/Exelon and other filings proposed that the PSC set incremental procurement budgets and allow cost recovery through a regulatory asset or surcharge; staff had suggested a per-megawatt-dollar placeholder in early comments. Utilities said a regulatory-asset framework can smooth short-term bill impacts while matching costs with benefits over the long life of storage assets.

Commissioners and stakeholders pressed the utilities on rate impacts. Commissioner questions repeatedly sought more concrete, locational siting studies, transparent benefit‑cost analyses for specific projects, and clearer proposals for how customers would be protected if market revenues or market rules change.

Pepco / SEIA joint distribution proposal

Pepco and SEIA presented a joint front-of-the-meter distribution proposal asking the PSC to permit the Exelon Maryland utilities to pursue 150 megawatts of distribution-connected storage across the Exelon service territories. Key elements they described:

- Allocation: Each Exelon utility would receive an allotment of the 150 MW target based on 2024 retail sales; the allotment would include both third‑party and utility‑owned targets. Pepco’s example showed a 30% minimum for utility‑ownership, a 30% minimum for third‑party ownership, and 40% flexibility across ownership models. - RFP / selection: Utilities would run separate solicitations for third‑party and utility‑owned projects and evaluate bids against cost and deployability criteria; reporting and PSC staff oversight would be part of the process. The parties proposed an annual solicitation cadence or until budget/capacity targets are met. - Timeline and check‑in: Pepco/SEIA proposed a November 2025 check‑in filing with detailed RFP and evaluation criteria, saying the initial high‑level authorization would be followed by a more detailed proposal before dollars are spent.

Potomac Edison proposal

Potomac Edison (Allegany‑area utility) proposed a smaller, tightly scoped pilot: up to 6 megawatts of distribution‑connected storage with a proposed cost cap of $28 million. Potomac Edison said it would (a) identify specific distribution constraints, (b) issue targeted RFPs to address those constrained locations, and (c) seek cost recovery via an annually reconciled surcharge. The utility proposed project‑level benefit‑cost analysis before each project moves forward.

Regulatory, legislative and market context

Witnesses referenced the commission’s narrow‑scope order (Order No. 91495) that opened the procurement docket and the Next Generation Energy Act’s prescriptive requirements for distribution‑ and transmission‑connected storage. That law requires, among other things, at least two Commission solicitations totaling 1,600 megawatts of transmission‑connected storage (two 800 MW solicitations, each device with a minimum four‑hour duration, with the first solicitation by January 1, 2026, as cited in testimony).

Commissioners repeatedly tied the discussion to developments in PJM’s wholesale markets: capacity price volatility, the resource adequacy outlook, and the interconnection queue. Multiple commissioners asked how state procurements would interact with projects already in the PJM queue and how procurement design could avoid duplicative payments or shifting unforeseeable market risk to ratepayers.

Stakeholder positions and PSC direction requests

- Utilities asked the PSC to authorize programs at a conceptual level and to provide direction on allocation among transmission and distribution targets so they could return with full RFPs, siting studies, and benefit‑cost analyses. - Office of People's Counsel, the Maryland Energy Administration (MEA) and several consumer‑oriented commenters urged strong bill‑impact checks, periodic review of cost recovery, and constraints on utility retention of market revenues where third parties supply resources. MEA specifically recommended limiting amortization recovery and restricting recovery to utilities’ cost of debt if amortization were used to avoid immediate bill shock. - Developers and industry groups argued that long‑term contracts and predictable revenue frameworks are necessary to enable financing of large transmission projects and urged the commission to design procurement rules that allow both full‑toll and partial‑toll options for bidders.

What the commission asked for next

Commissioners directed utilities to return with detailed program proposals, including RFP terms, selection criteria, cost‑allocation proposals and project‑level benefit‑cost analyses. The PSC signaled it expects more precise siting and interconnection information rather than high‑level targets alone.

Ending

The hearing underscored a central tension for the PSC: speed and scale versus cost and consumer protection. Utilities argued contract certainty and regulatory clarity will attract capital and accelerate storage deployment; commissioners and consumer advocates demanded more granular evidence that projects will produce net benefits and that customers will be shielded from undue forecast or market risk. The record will proceed with the utilities filing fuller program plans and the commission reviewing cost‑recovery approaches and consumer protections before approving projects for construction.