Stakeholders urge strong benefit‑cost framework as Maryland agencies, utilities outline storage procurement plans

The Maryland Public Service Commission heard detailed testimony on Jan. 22 from the Office of People's Counsel, technical witnesses and PSC staff about utility proposals to meet the state's energy‑storage goals, with repeated calls for a robust benefit‑cost framework, clearer procurement criteria and protections for ratepayers.

Alexis Lewis of the Office of People's Counsel told commissioners that the commission should “prioritize the establishment of a robust cost effectiveness framework as soon as possible to balance ratepayer impacts and achieve the statutory deadlines.” Lewis asked that each procurement include a benefit‑cost analysis (BCA) and suggested a ratepayer‑impact threshold, transparency around bid data under confidentiality agreements, and distributional equity tests so costs are not borne disproportionately by low‑income customers.

A technical witness described the difference between distribution‑connected and transmission‑connected storage and cautioned that distribution benefits — such as deferring local upgrades — depend on utilities having visibility and control systems in place and on the ability to dispatch resources at the right locations and times. The witness said, “These benefits are not guaranteed. They require appropriate processes and capabilities in place to actually be delivered.” He recommended that utilities’ procurement plans detail their ability to deliver claimed distribution benefits and align procurements with existing DERMS/DIRM implementation work.

The witness also explained the contrast between full‑tolling and partial‑tolling contracts for transmission‑connected storage. Under full tolling, the utility would control project operations and retain wholesale market revenues; under partial tolling the developer would retain energy and ancillary services revenues and the contract would primarily secure capacity value. The witness recommended BCAs for both contracting alternatives and criticized a proposed utility profit‑sharing structure that would give utilities 30% of net wholesale revenue above contract costs while leaving ratepayers responsible for 100% of net costs if revenues fell short.

Staff summarized the utilities’ filings and presented allocation and cost information. Potomac Edison proposed a 600‑megawatt, third‑party distribution procurement with a roughly 30‑month timeline; the Exelon utilities (BGE, Pepco and Delmarva) submitted two proposals — one joint Exelon/SEIA proposal for up to 150 megawatts and a broader Exelon plan for up to 600 megawatts that mixes utility‑ and third‑party‑owned devices. Staff noted that proposals lacked detailed delivery timelines and recommended that utilities provide more granular plans and project‑level BCAs.

Staff ran illustrative budget calculations using reported pilot project costs and a National Renewable Energy Laboratory baseline. Using pilot project data, staff calculated an average of about $4.65 million per megawatt, implying roughly $3.5 billion to procure 750 megawatts. Using the NREL 2024 baseline for a representative 60 MW / 240 MWh project produced a much lower illustrative figure of about $1.94 per kilowatt (equivalent to about $1.5 billion for 750 MW). Staff emphasized these are examples for commission consideration, not recommendations, and warned that simple dollars‑per‑MW caps could misalign incentives and fail to value non‑capacity benefits.

Commissioners pressed witnesses on timing and market risk. Commissioner Richard asked whether focusing on transmission‑connected projects currently in the PJM interconnection queue could be an expedient way to bring capacity online within a few years; parties agreed that pursuing near‑term transmission projects merits further discussion but that fair comparisons require BCAs and additional project detail. Commissioners repeatedly raised concerns about allocation methods (sales‑based vs. peak‑demand‑based), whether Maryland ratepayers could be exposed to costs while receiving a subset of benefits from PJM market participation, and the need for visibility and DERMS capability to realize distribution benefits.

Staff recommended that the commission consider selection criteria for solicitations (including round‑trip efficiency, degradation rates, response time, ELCC/effective load‑carrying capability and carbon‑abatement cost per MWh), and suggested the commission could impose phased budget controls or performance‑based recovery mechanisms if it chose to cap procurement costs. Staff also noted statutory changes (HB 10 35 / SB 9 37, the Next Generation Act) that establish a minimum 150‑megawatt front‑of‑meter distribution target and clarified some ownership and allocation language.

The commission left the record open for one week for supplemental filings and indicated it will issue an order on next steps after reviewing post‑hearing submissions.