AB 2111 revises California’s integrated resource planning (IRP) framework by directing the California Public Utilities Commission to require load‑serving entities to file periodic IRPs that meet state carbon and renewable policies, to incorporate probabilistic reliability modeling, and to coordinate procurement information with the Independent System Operator. The bill also builds a procedural backstop: if the CPUC finds unmet needs after reviewing IRPs, it can ask the Department of Water Resources to conduct competitive procurements for eligible clean resources.
For practitioners, the bill tightens the link between planning and operational planning (via explicit aggregation and reporting to the ISO), places new analytical requirements on the CPUC (including transmission and interconnection availability checks), and imposes non‑discrimination and cost‑allocation guardrails for any additional procurement. Those features change how utilities, community choice aggregators, developers, and grid operators plan projects, pursue contracts, and prioritize transmission upgrades.
At a Glance
What It Does
Requires each load‑serving entity to file an integrated resource plan under CPUC direction, mandates probabilistic short‑, mid‑, and long‑term reliability modeling, and requires the CPUC to aggregate short‑ and midterm procurement data and share anonymized reports with the ISO. If the CPUC finds remaining procurement needs, it may request the Department of Water Resources to run competitive solicitations as a procurement backstop, subject to eligibility rules.
Who It Affects
Investor‑owned utilities, community choice aggregators, electric service providers, the Department of Water Resources, the California Independent System Operator, renewable and storage project developers, and transmission planners are directly impacted; electrical cooperatives are in scope only above a high demand threshold.
Why It Matters
The bill shifts the CPUC’s planning role from qualitative oversight toward quantitative, probabilistic reliability assessment and makes procurement decisions contingent on transmission availability—raising the bar for demonstrating grid readiness and changing when the state steps in to centralize procurement.
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What This Bill Actually Does
AB 2111 reorients California’s IRP process around a few interlocking goals: meeting the state’s greenhouse gas objectives for the electricity sector, aligning resource procurement with those goals, and ensuring sufficient resource sufficiency across short, mid, and long horizons without imposing undue bill impacts. The CPUC must adopt a process and schedule for IRPs and ensure each load‑serving entity’s plan balances reliability, environmental objectives, cost, and resilience.
That balance includes demand‑side and supply‑side resources, opportunities to use existing renewables and distributed resources, and consideration of electrification trends and climate impacts when assessing future shortfalls.
The bill requires the commission to move beyond deterministic planning and to run probabilistic reliability models as part of the IRP public process. The models must assess whether there is enough capacity available in the short and midterm and be reviewed publicly at the same cadence as CPUC forecasts.
To support operational planning, the CPUC must aggregate reported short‑ and midterm procurement from all load‑serving entities and provide anonymized annual reports to the ISO, using counting conventions that let the ISO incorporate forward procurement into its grid planning. The CPUC’s modeling results must also feed into the state’s joint Reliability Planning Assessments.If, after reviewing IRPs and modeling results, the CPUC determines additional eligible energy resources are needed, it may identify what types of resources should be procured and may request that the Department of Water Resources use its central procurement authority as a backstop to procure those resources.
Any CPUC‑authorized procurement must be vetted against transmission and interconnection availability; the commission must confirm existing transmission plans provide sufficient infrastructure before approving procurement. The bill also includes several non‑market, equity, and administrative rules: priority attention to reducing localized air pollutants in disadvantaged communities, nondiscriminatory enforcement of procurement obligations (including potential penalties), rules to avoid cost shifting among customers, and a directive that the IRP process incorporate—rather than duplicate—other CPUC planning activities.
The Five Things You Need to Know
The bill sets a statutory procurement target requiring load‑serving entities to reach at least 60% eligible renewable energy by December 31, 2030.
The CPUC must aggregate short‑term and midterm procurement data from all load‑serving entities and annually deliver anonymized reports to the California Independent System Operator using counting conventions that support ISO grid planning.
If the CPUC finds a procurement need, it may request the Department of Water Resources to run competitive solicitations and enter contracts; the DWR may exercise that central procurement authority until January 1, 2035, and contracts approved under Water Code Section 80821 before that date remain in force for their term.
The bill prohibits load‑serving entities and the CPUC from including energy, capacity, or any attribute from Diablo Canyon Unit 1 after November 1, 2024, or Unit 2 after August 26, 2025, in adopted IRP portfolios or resource stacks.
The Department of Water Resources may procure pumped‑storage hydro only if the facility is 500 megawatts or less and was directly appropriated state funding before January 1, 2023.
Section-by-Section Breakdown
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IRP goals and required plan outcomes
This subsection lists the CPUC’s objectives for IRPs: meeting CARB’s electricity‑sector GHG targets, minimizing ratepayer impacts, ensuring just and reasonable service, strengthening transmission and distribution resilience, and prioritizing reductions in localized air pollution in disadvantaged communities. Practically, this establishes the decision criteria the CPUC must use when reviewing and directing LSE procurement choices and when ordering specific procurements for the market.
Probabilistic reliability modeling and public review
The CPUC must assess short, mid, and long‑term reliability using probabilistic models and review those results in public proceedings at the same frequency as IRP forecasts. The provision allows the commission to incorporate modeling from the Energy Commission and requires results to be included in the joint Reliability Planning Assessments, which creates an explicit technical link between the CPUC’s IRP process and broader state reliability analyses.
All‑source procurement flexibility with policy guardrails
The commission may authorize all‑source procurement—demand‑ and supply‑side resources, and hybrids—so long as plans meet the stated goals. The bill expressly permits procurement of resources that lower sector emissions even if they are not price‑competitive in the IRP timeframe, signaling that CPUC can weigh policy alignment above short‑run cost in procurement decisions.
DWR central procurement as a procedural backstop
If the CPUC finds a need after reviewing IRPs, it shall specify eligible resources to fill that need and may request the Department of Water Resources to conduct competitive solicitations. The DWR’s use of its central procurement function must follow Water Code Division 29.5 procedures and limited timing constraints, with an explicit mechanism to keep contracts entered before the cutoff in force for their duration—providing certainty for longer‑term contract enforcement.
Transmission/interconnection availability and cost allocation
Before approving procurement, the CPUC must complete a transmission and interconnection availability assessment and confirm the ISO’s last approved transmission plan supports cost‑effective procurement. The commission must ensure costs are fairly allocated and prevent cost shifting among customers, while allowing CCAs to self‑provide renewable integration resources consistent with statutory allocation rules.
Scope, special resource rules, and definitions
Electrical cooperatives fall under the statute only if they exceed a three‑year average demand threshold, the bill prevents inclusion of Diablo Canyon attributes beyond specified retirement dates, and it retires attributes for older non‑21st‑century nuclear thermal plants by a fixed date. The bill narrows what the DWR may procure (no fossil fuels or combustion except limited geothermal ancillary combustion) and sets an eligibility exception for pumped hydro tied to prior state funding. It also codifies short, mid, and long‑term time horizons for planning.
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Who Benefits
- Independent System Operator planners — they receive aggregated, anonymized short‑ and midterm procurement data and probabilistic modeling results, improving the ISO’s forward‑looking operational and transmission planning inputs.
- Disadvantaged communities — the bill requires the IRP process to prioritize minimizing localized air pollutants and greenhouse gas impacts in these areas, directing planners to weigh local health impacts when evaluating resources.
- Developers of long‑lead clean resources (e.g., large storage, geothermal) — the DWR backstop and the commission’s willingness to approve non‑price‑competitive resources that reduce sector emissions create new off‑ramps to bring certain projects to market.
Who Bears the Cost
- Load‑serving entities (utilities and CCAs) — they must produce detailed IRPs, participate in CPUC probabilistic modeling processes, and can be subject to ordered procurements or penalties for noncompliance, increasing planning and compliance workloads and potential procurement obligations.
- Ratepayers — any additional procurement authorized through IRPs or DWR backstop purchases could lead to higher short‑term costs depending on contract prices and transmission build needs, even as the statute requires efforts to minimize bill impacts.
- Department of Water Resources — if asked to exercise procurement authority, DWR must stand up competitive solicitations and manage contracts under Water Code procedures, adding administrative responsibilities and potential market exposure.
Key Issues
The Core Tension
The bill attempts to reconcile two valid but competing aims: preventing near‑term reliability gaps by centralizing procurement and modeling while avoiding premature or uneconomic investments that burden ratepayers; the tension lies in who decides a gap exists (technical modeling and counting rules) and whether the right lever to fix it is market procurement by LSEs, CPUC‑ordered procurement, or centralized DWR contracting—each path mitigates some risks and creates others.
AB 2111 layers quantitative reliability analysis and cross‑agency procurement into California’s planning architecture, but that approach raises operational and implementation questions. First, probabilistic modeling is data and assumption sensitive: different inputs about electrification, climate stress, and distributed resource adoption can yield different adequacy conclusions, and the statute leaves substantial discretion to the CPUC on modeling parameters and counting conventions.
That discretion matters because the CPUC’s modeling choices will determine whether the state views a need that triggers DWR procurement or additional ordered procurements by LSEs.
Second, the bill conditions any additional procurement on transmission and interconnection availability, which protects against stranded procurement but creates a coordination puzzle: many clean resources need transmission to be developed competitively, yet transmission upgrades often depend on clear forward resource commitments. Tying procurement approval to an existing ISO transmission plan could slow new resource entry or force projects to wait for expensive transmission builds.
Finally, granting DWR a temporal backstop (with contract continuation assurances) avoids on‑the‑ground uncertainty for projects, but it centralizes procurement risk in a state agency that operates under different contracting and financing constraints than private buyers—raising questions about market distortion, price discovery, and accountability for long‑term resource costs.
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