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SB 908

Relating to labeling requirements for items containing cannabis.

2025 Regular Session Introduced by Sara Gelser Blouin

Establishes triennial electric distribution system plans integrating DERs and non-wires solutions to meet state clean-energy goals, with enhanced oversight and data sharing.

In committee upon adjournment.
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Bill Summary · SB 908

SB 908 — Public Utilities: Electric Distribution System Plans (Affordable Grid Act)

Status snapshot
- Title: Public Utilities – Electric Distribution System Plans – Establishment (Affordable Grid Act)
- Key deadline in bill: Commission regulations/orders due by December 31, 2025
- Recurrent requirements: Electric distribution system plans submitted every 3 years; annual progress reports due each December 1 beginning 2026
- Fiscal estimate (Maryland): PSC special‑fund expenditures increase ~$465,400 in FY2026 (ongoing increases thereafter), offset by assessments on public service companies

Purpose and intent
- Strengthen and standardize electric distribution system planning to: (1) support State clean‑energy and climate targets (solar expansion, building electrification, EV deployment, storage, GHG reduction), (2) integrate distributed energy resources (DERs) cost‑effectively, and (3) increase reliability, resilience, and affordability for ratepayers.

Who is affected
- Investor‑owned electric companies, electric cooperatives, and municipal utilities (the Commission may tailor requirements by utility type)
- Gas companies operating within an electric company’s service area (required to participate in planning)
- Electricity suppliers, stakeholders, and the public (required engagement and information exchange)
- Public Service Commission (PSC) — new regulatory and review duties

Key provisions — what the bill requires
1. Regulations / orders (by Dec 31, 2025)
- PSC must adopt rules/orders to implement planning policies, require electric companies to file comprehensive electric distribution system plans (EDSPs) every three years, adopt monitoring metrics, require gas company participation, and create an information‑sharing framework with cybersecurity protections.

  1. Electric Distribution System Plans (every 3 years)

    • Must include: distributed energy resource (DER) and load forecasts for three planning horizons (short: 1–3 yrs; mid: 4–6 yrs; long: 7–10+ yrs), at least two scenario analyses, hosting‑capacity and load‑serving capability analyses, incorporation of innovations (e.g., virtual power plants, automated EV load management), assessment of non‑wires solutions and non‑capital alternatives, descriptions of stakeholder collaboration, cost‑minimization actions (including use of federal/state incentives), and explicit alignment with State clean energy/GHG goals.
    • Must demonstrate adoption of PSC’s performance metrics and compile public comments received.

  2. Public and stakeholder engagement

    • Electric companies must provide specified opportunities for public/stakeholder input during plan drafting.

  3. Plan review and approval

    • PSC reviews EDSPs and may only approve plans that: (a) met engagement requirements, (b) affordably advance State policy goals, (c) cost‑effectively advance State policy to the greatest extent possible, (d) adequately incorporate non‑wires solutions, and (e) adequately address stakeholder comments. PSC may reject plans that fail to advance policy/cost objectives.
    • PSC may stagger reviews but must review each company’s plan at least once every three years.

  4. Metrics and information sharing

    • PSC must adopt and maintain metrics to monitor progress in categories such as system reliability; DER integration (solar, storage, EVs); system management (peak load, time‑of‑use programs, hosting capacity); use of non‑wires solutions; advancement of State targets; and future capabilities (storage flexibility, flexible interconnection, local demand response).
    • PSC must adopt an information‑sharing framework enabling secure exchange of geospatial and equipment data among utilities, suppliers, and the public.

Fiscal and operational impacts
- PSC: increased regulatory workload and estimated special‑fund expenditures ($465,400 in FY2026; higher in subsequent years), funded by assessments on public service companies.
- Utilities: increased planning, data‑sharing and stakeholder engagement responsibilities; potential upfront administrative and program costs.
- Ratepayers: bill aims to minimize costs to ratepayers via targeted planning and use of federal/state incentives, but utilities may incur additional planning costs that could be reflected in future rate proceedings if not offset.
- Municipal utilities and gas companies: subject to participation requirements and potentially new obligations under the information‑sharing framework.

Implementation timeline (high‑level)
- PSC regulations/orders: by Dec 31, 2025
- First round of progress reporting by utilities: annual reports due Dec 1, 2026, and each Dec 1 thereafter
- EDSP filing cadence: every 3 years per utility after PSC rulemaking

Net effect
- The bill creates a structured, statewide approach to distribution planning intended to accelerate DER integration, electrification, and achievement of climate goals while promoting affordability and reliability. It increases regulatory oversight and data‑sharing requirements and imposes additional planning and administrative obligations on utilities and PSC, with measurable near‑term fiscal impacts on PSC funded by utility assessments.

Compiled from official sources — confirm details with the bill’s official record.

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