This bill revises the Renewables Portfolio Standard (RPS) rules that apply to local publicly owned electric utilities (LPOUs) by defining “large hydroelectric generation” and allowing LPOUs with substantial in‑state hydro output to reduce the quantity of eligible renewable energy resources they must procure in a compliance year. It creates a threshold test (more than 40 percent of retail sales from large hydro in a year) that, when met, caps the utility’s additional renewable procurement obligation at the lesser of its unmet retail demand or a soft target set by the Energy Commission.
The bill also preserves special treatment for certain city‑county utilities that get more than 67 percent of their power from in‑state hydro that they own and operate.
Beyond the hydro carve‑outs, the bill clarifies treatment of voluntary green pricing and shared renewable programs, tightens time‑of‑contract and ownership rules for counting hydro toward the threshold, and folds enforcement into the Energy Commission/CARB penalty framework. For compliance officers, regulators, and renewable project developers, AB 34 reallocates near‑term demand for build‑out of non‑hydro renewables and creates new accounting and verification requirements that the Energy Commission must operationalize.
At a Glance
What It Does
AB 34 defines “large hydroelectric generation” and allows LPOUs that source more than 40% of retail sales from such hydro to limit their additional eligible renewable procurement for that year to either their remaining unmet retail demand or a soft target set by the Energy Commission. It preserves an exemption for a city‑county utility that gets >67% from in‑state hydro it owns, and adds rules about contract vintage, REC treatment for voluntary programs, and enforcement by the Energy Commission with CARB penalties.
Who It Affects
The bill directly affects California municipal and other locally owned utilities, owners/operators of in‑state hydro facilities, renewable energy generators seeking RPS buyers, the California Energy Commission (CEC), and the State Air Resources Board (CARB). It also affects retail customers participating in voluntary green pricing programs whose credited energy is excluded from RPS accounting.
Why It Matters
By allowing existing large hydro to substitute for incremental RPS procurement under specific conditions, AB 34 reshapes the immediate market for new renewable projects and reallocates compliance obligations across utilities. The bill forces the Energy Commission to create technical accounting, verification, and adjustment procedures that will determine how large hydro is measured, what contracts count, and how the state’s near‑term renewable targets are met.
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What This Bill Actually Does
AB 34 modifies the RPS framework for local publicly owned electric utilities by creating a narrowly drawn exception for in‑state hydroelectric generation that is not already defined as an eligible renewable resource. The bill defines “large hydroelectric generation” as electricity from existing in‑state hydro facilities that, as of January 1, 2018, were owned by an LPOU, the federal government as part of the Central Valley Project, or a joint powers agency.
If an LPOU receives more than 40 percent of its retail sales from such large hydro in any compliance year, the utility may cap the amount of additional eligible renewable procurement it must undertake that year. The cap is the lesser of (a) the portion of retail sales not met by its large hydro, or (b) the Energy Commission’s “soft target” for the intervening compliance‑period years.
The bill draws several bright lines to limit gaming: contract extensions or renewals entered after the statute’s effective dates generally cannot be used to push a utility over the 40 percent threshold, although legacy agreements with the Western Area Power Administration or the federal Central Valley Project that were in effect on January 1, 2015, remain eligible. AB 34 also preserves other existing RPS rules — an LPOU keeps discretion over its resource mix and may still adopt delay or cost‑limitation measures consistent with current law.AB 34 also addresses adjacent accounting matters: kilowatthours credited to customers under voluntary green pricing or shared renewable programs can be excluded from an LPOU’s retail sales for RPS calculation, but any associated RECs must be retired on behalf of participating customers and cannot be monetized for compliance.
The Energy Commission must adjust procurement quantities to reflect any reductions under the large‑hydro rule, and the Commission will adopt enforcement procedures including notices of violation; CARB may impose penalties comparable to those applied to retail sellers, with penalty proceeds directed to the Air Pollution Control Fund for local emissions or GHG reduction projects.Finally, the bill contains a small‑utility accommodation: an LPOU with 15,000 or fewer customer accounts that was in existence before 2009 and is interconnected to a WECC balancing authority outside California may count out‑of‑state WECC‑connected resources as eligible under specified conditions, provided accounting and Energy Commission verification requirements are satisfied.
The Five Things You Need to Know
The bill defines “large hydroelectric generation” by owner and vintage: an existing in‑state hydro facility that, as of Jan. 1, 2018, was owned by an LPOU, the federal government as part of the Central Valley Project, or a JPA formed under the Joint Exercise of Powers Act.
If an LPOU receives more than 40% of its retail sales from large hydro in a compliance year, its additional eligible renewable procurement for that year is capped at the lesser of its unmet retail demand or the Energy Commission’s soft target for that compliance period.
Contract renewals or extensions entered after the reference dates cannot be counted toward the 40% large‑hydro determination, except that agreements in effect on Jan. 1, 2015 with WAPA or the federal Central Valley Project remain eligible.
Kilowatthours credited to participating customers under voluntary green pricing or shared renewable programs can be excluded from an LPOU’s retail sales for RPS purposes, but any associated RECs must be retired for the participant and cannot be used for compliance or monetized.
The Energy Commission enforces the adjustments, may issue notices of violation, and refers noncompliance to CARB, which can impose penalties comparable to those for retail sellers; penalty revenue must go to the Air Pollution Control Fund for local emissions or GHG reduction projects.
Section-by-Section Breakdown
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Procurement plans and compliance periods for LPOUs
These subsections restate that each local publicly owned electric utility must adopt a renewable energy resources procurement plan integrated with its broader integrated resource plan, and they lay out the multiyear compliance periods and baseline procurement targets. Practically, this anchors the LPOU’s annual procurement obligations to the established RPS timelines and makes the later large‑hydro adjustments operate against defined compliance periods rather than ad hoc years.
RPS percentage targets and multiyear compliance framework
Subdivision (c) codifies the historic percentage milestones (20%, 25%, 33%, 44%, 52%, 60%) and directs the Energy Commission to set multiyear compliance periods thereafter. For implementers, this section is the reference yardstick that the Energy Commission will use when applying any reduction granted under the large‑hydro rule; the CEC must reconcile reductions with these statutory targets when calculating adjusted procurement quantities.
City‑county utility >67% in‑state hydro carve‑out
This paragraph gives a narrow exemption: a city and county utility that receives more than 67% of its electricity from in‑state hydro that it owns and operates (and that does not qualify as a renewable electrical generation facility under Public Resources Code §25741) only needs to procure eligible renewables to meet demand not already satisfied by its hydro. This is a location‑specific, ownership‑based exemption that will meaningfully reduce RPS obligations for that single type of municipal utility.
Definition and mechanics for the large‑hydro threshold and procurement reductions
Subdivision (k) defines “large hydroelectric generation,” sets the critical 40% of retail sales threshold, and prescribes how the LPOU’s procurement obligation is reduced (lesser of unmet demand or CEC’s soft target). It also bars counting extension or renewal agreements toward the 40% test, with an explicit carve‑out preserving certain WAPA/CVP agreements in effect Jan. 1, 2015. The CEC must adjust the utility’s total RPS procurement quantities for the compliance period to reflect such reductions — which creates measurement, contract‑verification, and accounting tasks for the agency.
Treatment of unavoidable long‑term coal contracts
This provision allows an LPOU with legacy coal commitments (entered before June 1, 2010) to demonstrate that cancellation would cause significant economic harm and, if approved, hold down its renewable procurement target to no less than an average of 33% for the affected compliance period. The Energy Commission must approve any such reduction, so this acts as a limited, conditional relief route for utilities with stranded fossil commitments.
Enforcement, penalties, and use of penalty proceeds
These subsections require the Energy Commission to adopt enforcement regulations (including notice of violation processes) and direct the Commission to refer noncompliance to CARB. CARB may impose penalties comparable to those used for retail sellers; collected penalties are deposited in the Air Pollution Control Fund and, once appropriated, must be spent on reducing emissions or GHGs in the same geographic area as the violating LPOU. This ties enforcement to the existing state penalty architecture and earmarks penalty proceeds for local mitigation.
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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
- Hydro‑dependent municipal utilities that own in‑state large hydro — They can count in‑state large hydro against RPS obligations and potentially avoid near‑term purchases of incremental renewables, reducing compliance costs and procurement exposure.
- A city‑and‑county utility with >67% in‑state hydro — The statute limits its RPS obligation to only the electricity demand not satisfied by its own hydro, effectively minimizing its need to procure additional eligible renewables.
- Owners and operators of existing in‑state large hydro facilities — Their generation gains additional value as it displaces RPS procurement obligations, improving contract leverage and preserving revenue streams.
- Customers enrolled in voluntary green pricing/shared renewable programs — Their credited kilowatthours can be excluded from utility retail sales and their associated RECs are retired on their behalf, securing the environmental attribute for participants.
- Utilities with unavoidable coal contracts approved by the CEC — They may lower their RPS procurement target for the relevant compliance period to avoid double procurement burdens during contract wind‑down.
Who Bears the Cost
- New non‑hydro renewable project developers — Reduced procurement demand from hydro‑heavy LPOUs shrinks near‑term market opportunities and may slow project financing and construction timelines.
- Other LPOUs and retail sellers — If hydro‑heavy utilities reduce procurement, maintaining statewide renewable build‑out may shift incremental demand onto other utilities, raising their procurement burden or market prices.
- California Energy Commission and CARB — Implementing the statute requires new accounting rules, contract verification workflows, soft‑target methodologies, and an enforcement program, imposing administrative and technical costs.
- Ratepayers in utilities that receive penalties — Although penalty funds are earmarked for local emission reductions, customers may indirectly bear program costs through administrative compliance and the tradeoffs utilities make when reallocating procurement.
- Auditors and compliance teams — New verification rules (ownership vintage, contract start dates, delivery and WECC accounting) increase compliance complexity and resource needs for utility procurement and legal teams.
Key Issues
The Core Tension
The central tension is between administrative fairness to utilities that historically and legitimately rely on in‑state hydro (and the desire to avoid imposing sudden, potentially harmful procurement costs) and the integrity and market signal function of the RPS (which seeks to drive new non‑hydro renewable build‑out and avoid backsliding on greenhouse gas goals). Granting hydro‑based relief softens near‑term cost impacts but reduces guaranteed demand for new renewables and complicates accounting and enforcement — there is no simple fix that fully protects both fiscal fairness for affected utilities and the RPS’s decarbonization incentives.
AB 34 threads a narrow policy needle: it preserves the existing RPS architecture while carving out accounting relief for utilities that already rely heavily on in‑state hydro that is not defined as an eligible renewable resource. That relief depends on precise vintage, ownership, and contract rules that the Energy Commission must operationalize.
Key implementation issues include establishing how deliveries from large hydro are measured against retail sales (hourly vs. monthly vs. annual), whether generation shifts across balancing authorities will change eligibility, and how to verify that generation is not simultaneously used to meet obligations in other jurisdictions. The statute’s prohibition on counting post‑reference contract renewals reduces but does not eliminate incentives to restructure contracts or ownership to qualify facilities as large hydro under the Jan. 1, 2018 ownership test.
The bill also creates distributional and market effects. Allowing some LPOUs to substitute large hydro for incremental renewables reduces immediate demand for new wind and solar, which could slow project development or shift procurement costs onto other utilities.
Meanwhile, retiring RECs for voluntary program participants prevents double‑counting but reduces trading liquidity that developers rely on. Enforcement will hinge on the Energy Commission’s technical rules (soft target calculation, proximity standards for excluded generation, WECC accounting), and those choices will materially affect which utilities actually receive relief and how much the statewide renewable market contracts or rebalances.
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