AB 2163 establishes a clear state policy: 90% of retail electricity sales must come from eligible renewable and zero‑carbon resources by 2035, 95% by 2040, and 100% by 2045. It also requires that all state agencies procure 100% zero‑carbon electricity by 2035 and directs state regulators to implement the policy in a way that does not increase greenhouse gas emissions elsewhere in the western grid or rely on resource shuffling.
The bill matters because it pairs aggressive decarbonization targets with explicit anti‑leakage language and a legal caveat tied to the Commerce Clause, while carving out a specific exclusion for Diablo Canyon and flagging Imperial County and the so‑called Lithium Valley as high‑priority energy development areas. For compliance officers, regulators, and utility planners, AB 2163 signals new planning priorities and coordination requirements without creating fresh procurement authorities — instead, it directs agencies to use existing statutory programs to achieve the goals.
At a Glance
What It Does
Declares state policy targets for eligible renewable and zero‑carbon supply (90% by 2035, 95% by 2040, 100% by 2045) and requires state agencies to reach 100% zero‑carbon by 2035. It orders the CPUC, CEC, and CARB to implement the policy while preventing emissions increases elsewhere in the western grid and prohibiting resource shuffling.
Who It Affects
State energy and environmental agencies (CPUC, CEC, CARB) for planning and coordination; retail sellers and balancing authorities for compliance planning; developers and local governments in Imperial County/Lithium Valley for future projects; Diablo Canyon’s output is explicitly excluded from counting toward the targets.
Why It Matters
By coupling firm timelines with anti‑leakage language, the bill raises measurement and accounting questions across the western electricity market, constrains how contracts and RECs can be used, and sets a policy that will drive long‑range resource planning, interagency coordination, and regional engagements.
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What This Bill Actually Does
AB 2163 is a policy bill that sets statewide decarbonization benchmarks and directs state regulators to fold those benchmarks into planning and implementation. It states percentage targets for eligible renewable and zero‑carbon resources to supply retail electricity sales across California (90% by 2035, 95% by 2040, and 100% by 2045) and an accelerated 100% zero‑carbon procurement target for state agencies by 2035.
The bill frames those targets as a state policy that must be reflected in “all relevant planning” done by the California Public Utilities Commission (CPUC), the California Energy Commission (CEC), the State Air Resources Board (CARB), and other state agencies.
The bill places two constraints on how the targets are to be pursued. First, it requires that the transition not increase greenhouse gas emissions elsewhere on the western grid and forbids “resource shuffling,” language designed to prevent accounting practices that shift emissions geographically without reducing them in aggregate.
Second, it requires agencies to pursue the policy in a way that is consistent with the Commerce Clause (it cites clause 3 of Section 8 of Article I of the U.S. Constitution). Those constraints will shape how the state counts imports, credits, and contractual arrangements in compliance and planning exercises.
AB 2163 does not create new statutory procurement powers; instead, it instructs agencies to use programs they already have authority to run under existing law to meet the policy goals.The bill also includes targeted mechanics and exceptions that matter for implementation. It explicitly directs agencies to preserve system reliability and to avoid unreasonable customer bill impacts, it excludes Diablo Canyon’s Unit 1 and Unit 2 energy and attributes from counting toward the targets after August 26, 2025, and it carves out existing onsite cogeneration and long‑standing over‑the‑fence arrangements from new CPUC requirements.
Finally, the statute calls out Imperial County and the Lithium Valley as areas whose energy potential and capacity the state should consider in planning — a signal to developers and local governments that those regions are priorities for future build‑out. Taken together, the bill is a policy roadmap with specific accounting guardrails, implementation constraints, and a mix of express inclusions and exclusions that will require interagency coordination to operationalize.
The Five Things You Need to Know
The bill sets three statewide targets for retail electricity supply from eligible renewable and zero‑carbon resources: 90% by 12/31/2035, 95% by 12/31/2040, and 100% by 12/31/2045.
It requires 100% zero‑carbon procurement for electricity serving all state agencies by 12/31/2035, an earlier deadline than the general retail‑sales timetable.
AB 2163 explicitly forbids resource shuffling and requires that California’s transition ‘shall not increase carbon emissions elsewhere in the western grid,’ creating an anti‑leakage policy obligation.
The bill bars the use of Diablo Canyon Unit 1 and Unit 2 energy or attributes toward meeting the statewide policy after August 26, 2025.
Agencies must implement the policy using programs already authorized under existing statutes; the bill does not create new procurement authorities and preserves existing PURPA obligations.
Section-by-Section Breakdown
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State decarbonization targets and anti‑leakage rule
This subsection sets the numeric targets and frames them as state policy to be incorporated into all relevant planning by CPUC, CEC, CARB, and other agencies. It adds the anti‑leakage requirement — the transition cannot increase greenhouse gas emissions elsewhere in the western grid — and it forbids resource shuffling. Practically, this forces planners to think about accounting for imports, energy credits, and regional generation so that actions in California do not simply shift emissions to neighboring balancing authorities.
Reliability, rate impacts, and cross‑sector equity constraints
These clauses bind agencies to protect electric system safety and reliability and to prevent unreasonable impacts on electricity, gas, and water customer bills, explicitly asking agencies to consider both economic and environmental costs and benefits. They also direct agencies, to the extent feasible and lawful, to encourage emission reductions in other sectors so that the electricity sector isn’t held to a standard that other sectors do not meet. For planners and compliance teams, this raises the bar for integrated resource planning and benefit‑cost analyses tied to the policy.
Relationship to RPS enforcement, Diablo Canyon exclusion, and priority regions
Clause (4) preserves the existing regulatory framework for oversight and enforcement under the California Renewables Portfolio Standard Program and named statutory sections, signaling that AB 2163 is not intended to rewrite RPS enforcement mechanics. Clause (5) removes Diablo Canyon Unit 1 and Unit 2 energy and attributes from counting toward the policy after August 26, 2025, which will affect near‑term resource accounting and reliability conversations. Clause (6) instructs agencies to consider Imperial County and Lithium Valley’s development potential, an affirmative nod toward channeling future projects and investment into those regions.
Non‑interference with PURPA obligations
This short clause makes clear that retail sellers’ obligations under the federal Public Utility Regulatory Policies Act of 1978 (PURPA) remain unchanged. That preserves developers’ rights to qualifying facility contracts and ensures the bill cannot be read to limit those federal protections.
Implementation through existing programs
Rather than creating new authorities, the bill directs CPUC, CEC, and CARB to accomplish the policy using programs they already have authority to run under current statutes. For agencies, that means repurposing and coordinating existing grant, procurement, planning, and regulatory tools instead of relying on fresh enabling legislation.
Cogeneration and over‑the‑fence carve‑outs
The bill prohibits the CPUC from imposing new requirements on nonmobile self‑cogeneration facilities that serve onsite load or on over‑the‑fence arrangements existing before December 20, 1995. This protects long‑standing onsite generation arrangements from retroactive regulatory change tied to the new policy.
Affirmation of local and other actors’ authority to accelerate
This provision clarifies that nothing in AB 2163 prevents local governments or other entities from moving faster than the statewide targets. It preserves local autonomy to adopt more aggressive procurement or decarbonization measures.
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Explore Energy in Codify Search →Who Benefits and Who Bears the Cost
Every bill creates winners and losers. Here's who stands to gain and who bears the cost.
Who Benefits
- State agencies: The 2035 100% zero‑carbon deadline gives state agencies a clear procurement policy and political cover to prioritize zero‑carbon contracts and on‑site clean power investments.
- Renewable and zero‑carbon developers: Developers building projects in Imperial County and Lithium Valley gain a policy signal prioritizing those regions, which could accelerate permitting, interconnection, and investment decisions.
- Environmental and climate organizations: The explicit anti‑leakage and anti‑resource‑shuffling language protects the integrity of California’s emissions accounting and supports genuine emissions reductions rather than paper transactions.
- Owners of legacy onsite cogeneration/over‑the‑fence facilities: Operators with qualifying pre‑1995 arrangements keep existing regulatory treatments, avoiding new CPUC requirements that could impose retroactive costs.
Who Bears the Cost
- Retail sellers and utilities: They will face planning, contracting, and accounting obligations to align procurement with the targets and anti‑leakage requirements, with potential procurement cost increases during the transition.
- Ratepayers: The bill directs agencies to prevent unreasonable bill impacts but does not eliminate the possibility that accelerated procurement, reliability investments, or replacement capacity will raise rates or bills for consumers.
- CPUC/CEC/CARB and staff: Agencies bear coordination and analytic costs to develop cross‑border emissions accounting, regional engagement, and to adapt existing programs to deliver the targets without new statutory tools.
- Diablo Canyon stakeholders (owner/operators and related contractors): Excluding Diablo Canyon from counting toward targets after August 26, 2025 reduces the plant’s role in meeting state policy and may accelerate planning for replacement resources and community transition needs.
Key Issues
The Core Tension
The central dilemma is speed versus systemic integrity: the bill pushes for rapid decarbonization of electricity while demanding that California not shift emissions off its books or undermine reliability and affordability — a set of goals that can conflict in practice and will force regulators to choose between quicker emissions reductions, higher near‑term costs, increased regional coordination, or slower, more conservative transitions.
AB 2163 combines ambitious targets with constraints that create real implementation complexity. The anti‑leakage and anti‑resource‑shuffling requirements are conceptually straightforward but technically demanding: measuring whether California’s actions ‘increase carbon emissions elsewhere in the western grid’ will require new accounting conventions, data sharing with neighboring balancing authorities, and decisions about how to treat imports, firming capacity, and contractual attributes.
Those measurement choices will determine whether particular contracts or REC transactions are permissible under the bill’s policy.
The bill’s language stops short of granting new procurement powers; it instructs agencies to use existing programs. That approach limits legal risk but raises a procedural question: if current statutory authorities prove insufficient to deliver the targets, the state would need further legislation or creative repurposing of programs.
The explicit exclusion of Diablo Canyon energy and attributes after a specific date is a blunt instrument: it clarifies policy preference but also forces earlier and potentially costly replacement planning and creates timing pressure on reliability and workforce transition efforts. Finally, the reference to Imperial County and Lithium Valley is deliberately broad; without follow‑up guidance, it is unclear whether that consideration will translate into permitting, transmission upgrades, dedicated procurement, or only planning studies.
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