Director Paul Pinsky, Maryland Energy Administration, told the Economic Matters Committee that the administration’s analysis of pathways to 100% clean electricity projects a major increase in generation capacity and significant policy tradeoffs.

“This study should be seen as a starting point for conversation. It’s not an endpoint. It is a foundation,” Pinsky said as he introduced the 72‑page report prepared for the committee.

The report presents three modeling scenarios: (1) a pathway that assumes 100% of the state’s generation is produced in Maryland; (2) a pathway that assumes Maryland imports 20% of its electricity; and (3) a “maintenance” case that continues current imports at roughly 39–40%. The administration said it asked the consultant to constrain some resource deployments (for example, caps on onshore solar and wind and limits on offshore wind) so the outputs would be geographically realistic for Maryland.

Under the study’s primary decarbonization run, Maryland’s current installed capacity of about 12 gigawatts would need roughly 9.6 additional gigawatts—about a 75% increase—by 2035 to meet a 100% in‑state clean generation benchmark. The modeling showed solar and land‑based wind are the least‑cost clean resources but are limited by land availability and siting constraints; the model instead leaned heavily on expanding nuclear output and deploying offshore wind where feasible.

The study treats nuclear generation as emissions‑free for purposes of the modeling and reports an approximate 185% increase in nuclear capacity in the decarbonization scenario (the consultant’s output included one roughly 2.2‑gigawatt traditional reactor and two ~600‑megawatt small modular reactors in that run). The report also shows offshore wind deployments rising in some scenarios (to roughly 3.9 gigawatts in the principal run), but MEA staff warned those projects face financing and permitting uncertainty.

Ryan Opsahl, Director of Energy Policy at the Maryland Energy Administration, described the base case and the decarbonization runs and warned the model’s outputs are sensitive to the caps and assumptions MEA provided. Opsahl noted the model assumes PJM projections for behind‑the‑meter residential solar (about 2.5 gigawatts) and includes modest increases in utility solar and onshore wind in the base case.

Committee members pressed MEA on reliability, costs, and near‑term risks to ratepayers. Several legislators asked whether the modeling accounted for expected data‑center load, battery storage, reconductoring or other nongeneration solutions. MEA said the consultant used PJM’s load forecast (including some electrification assumptions) and assumed one large data center of about 800 megawatts in the base run; MEA representatives said they are working with the consultant on additional runs that would explicitly model higher data‑center scenarios. MEA also said batteries were included in the model but that system‑level modeling undercounts the full economic value batteries could capture in distribution‑level markets and that a more focused reliability and peak‑capacity study would be required to examine those questions in depth.

On imports and supply mix, Pinsky told the committee the state currently imports roughly 36–40% of its electricity and that the gap between in‑state generation and load is a long‑standing condition. The report cites Maryland’s Climate Solutions Now Act (the state law calling for a 60% greenhouse‑gas reduction by 2031) and the governor’s executive order directing a 100% clean‑energy analysis as drivers for the study.

MEA presented several policy recommendations summarized in the report including: evaluating procurement mechanisms for large projects (including a procurement approach for nuclear), revisiting the alternative compliance payment (ACP) structure to maintain stronger renewable credit prices, using application escrow accounts for offshore wind to protect the state from failed bidders, and standing up a coal‑site reuse program to identify generation sites (for example, for SMRs or other resources) where existing transmission infrastructure might be repurposed.

Committee members emphasized affordability and the need for more granular reliability analysis. Several legislators said they supported exploring nuclear options (including small modular reactors) and repurposing retired fossil‑fuel sites, but also warned that siting, federal permitting, financing and potential cost impacts on ratepayers will constrain how quickly any buildout can occur. MEA repeatedly told the committee the 2035 100% in‑state generation scenario is a heavy lift and not yet law; the governor’s call for 2035 is an executive objective and would require legislative action to become binding.

The presentation concluded with committee members asking MEA for follow‑up analysis—additional model runs that include alternate import assumptions and data‑center load cases, a targeted reliability/peak‑capacity study, a reconductoring feasibility analysis, and more detailed cost‑impact work for ratepayer and fiscal planning. MEA said it will provide additional model runs and further analysis to the committee as they become available.