Bill
AB 2369
AB 2369 strengthens resource adequacy rules to recognize energy-only resources, accelerate transmission planning, and integrate storage and demand response for reliable, decarboniz
AB 2369 (2025-2026) – Electricity: resource adequacy requirements: transmission facility planning
Jurisdiction: California
Overview
AB 2369, introduced by Assembly Member Chris Rogers, would modify how California regulates resource adequacy (RA) and transmission planning to better recognize energy-only resources, accelerate transmission development, and emphasize reliability and grid integration of renewable and zero-carbon resources. The bill amends several sections of the Public Utilities Code and includes provisions aimed at enhancing planning, cost recovery, and enforcement related to RA and transmission planning.
Main purpose and intent
- Expand and strengthen the RA program to recognize the value of energy-only resources for grid reliability.
- Promote timely development, interconnection, and interregional transmission capacity to deliver renewable and zero-carbon resources to load centers.
- Encourage increased use of grid infrastructure, including energy storage, to support reliability, decarbonization, and resilience.
- Improve planning projections and coordination among the CPUC, Energy Commission, and ISO to guide transmission investments.
Key provisions and changes
1) Resource adequacy program enhancements (Section 380)
- CPUC, in consultation with ISO, shall establish RA requirements for all load-serving entities (LSEs) and ensure reliability while advancing clean energy and greenhouse gas reduction goals.
- RA objectives added to include:
- Recognizing a reliability contribution from energy-only resources (e.g., non-capacity resources that support reliability, storage, decarbonization).
- Maximizing timely development and interconnection of resources identified in planning.
- Promoting increased use of grid infrastructure and leveraging storage for reliability and cost efficiency.
- LSEs must maintain: physical generating capacity, energy storage, and electrical demand response (EDR) adequate to meet load requirements, including peak demand and reserves.
- Ensure deliverability of resources to required locations/times to maintain reliability (system and local).
2) Planning, reporting, and cost allocation (Section 380)
- RA enforcement remains nondiscriminatory across LSEs; identical RA, RPS, and integrated resource planning requirements apply.
- Utilities must provide sufficient information (load data, measures to ensure RA) for compliance.
- CPUC must publish annually an RA effectiveness metric: the share of RA met by eligible renewable, zero-carbon resources (including large hydro and nuclear) and energy storage.
- Costs of meeting RA (reasonableness determined by CPUC) are fully recoverable on a fully nonbypassable basis from those customers on whose behalf the costs are incurred; exclusions apply to CCAs and certain direct customers as specified.
- Valuation framework for load-modifying and supply-side DR resources; coordinate with Energy Commission and ISO to reflect demand shifts in forecasts and planning.
3) Transmission-focused planning and guidance (Sections 454.57; related policy)
- Upgraded RA planning integrates transmission-focused guidance to ISO on resource portfolios and regions, to identify needed transmission facilities for interconnection and reliability.
- CPUC and Energy Commission must annually project: load growth (including electrification), resource portfolios, offshore wind, imports, and congestion mitigation opportunities.
- Projections must cover at least 15 years, with consideration of cost-effective alternatives to transmission capacity expansions (e.g., storage, local resources).
- Provisions to accelerate identifying and approving priority transmission projects, including consideration of wildfire risk and regional delivery of renewables.
4) Definitions and clarifications (Section 380 and 454.57)
- Defines “Local capacity area” (transmission-constrained load pocket) and “Nonpreferred resources” (non-renewable/zero-carbon resources per Section 454.53).
- Clarifies LSEs include electric corporations, electric service providers, and community choice aggregators (CCAs); excludes certain public ownerships and customer-generated on-site resources under specified conditions.
Procedural and timeline aspects
- Referred to and amended within the Assembly, with committee review ongoing as of the latest action: re-referred to Committee on Utilities and Energy (U. & E.).
- The bill includes the ongoing requirement for annual projections and guidance coordinated among CPUC, Energy Commission, and ISO, aligning with the ISO’s planning cycles.
- No new state-level appropriation; it is a policy/administrative reform with costs potentially falling under existing RA cost recovery mechanisms.
Impact considerations
- For LSEs (investor-owned utilities, electricity providers, CCAs): stricter RA requirements incorporating energy-only resources and more storage/EDR, with potential changes in planning, reporting, and cost recovery.
- For transmission planning: explicit emphasis on proactive transmission development, regional resource allocation, and consideration of wildfire risk and long lead times.
- For ratepayers and local agencies: cost recovery remains fully nonbypassable for RA-related costs, subject to CPUC determinations; potential future rate impacts depend on RA and transmission decisions.
- For the renewable/zero-carbon resource pipeline: aim to reduce bottlenecks by integrating transmission planning with resource adequacy goals, potentially accelerating project interconnection and delivery.
Compiled from official sources — confirm details with the bill’s official record.
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