SB 919 amends two sections of the Public Utilities Code to accelerate in‑state biomethane deployment by changing how projects are funded and how utilities recover related costs. It extends the existing monetary incentive program for biomethane projects through December 31, 2030, raises per‑project incentive caps, and explicitly authorizes the California Public Utilities Commission (CPUC) to allow gas utilities to recover certain interconnection investment costs through rates.
The bill also authorizes the CPUC to use revenues received by gas corporations from the direct allocation of greenhouse‑gas allowances to add funding to the incentive program after January 1, 2027. SB 919 combines higher per‑project limits, a new funding source, and formal rate‑recovery rules (with numerical limits) — a package that makes utility‑led interconnections more feasible but shifts identifiable financial exposure to ratepayers and creates new oversight tasks for regulators.
At a Glance
What It Does
SB 919 extends the biomethane monetary incentive program to December 31, 2030, increases per‑project caps (general projects to $3M; dairy cluster projects to $5M), allows CPUC to use gas corporations' allocated greenhouse‑gas allowance revenues to fund the program after Jan 1, 2027, and requires CPUC to permit gas utilities to recover interconnection investments in rates subject to limits.
Who It Affects
Gas corporations operating in California, biomethane/RNG project developers (especially dairy cluster operators and aggregators), CPUC staff who must implement new recovery and funding rules, and ratepayers who ultimately fund utility investments through rates.
Why It Matters
The bill lowers upfront capital barriers for in‑state biomethane by combining higher incentives with utility ratebasing, which can shorten project timelines and reduce procurement costs — but it also formalizes a mechanism that reallocates certain project costs onto gas ratepayers and ties program funding to variable allowance revenues.
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What This Bill Actually Does
SB 919 updates California’s existing biomethane monetary incentive program and the regulatory rules around utility involvement. The bill pushes the program’s life out to the end of 2030 and raises the money available per project so larger or more complex projects—particularly multi‑dairy cluster projects that require gathering lines—can qualify for higher support.
The text treats dairy cluster projects differently by allowing a $5 million cap that explicitly covers both interconnection and gathering line costs directed at reducing short‑lived climate pollutants.
A key new lever is the CPUC’s ability to tap revenues that gas corporations receive through the state’s cap‑and‑trade allowance allocations (including accrued interest) beginning January 1, 2027. Rather than rely solely on the original incentive pot established in CPUC Decision 15‑06‑029, the commission can authorize supplemental funding using those allowance receipts, which effectively links biomethane program funding to carbon allowance flows to gas suppliers.The bill also changes who pays for interconnection infrastructure.
It requires the CPUC, by a statutory date tied to 2026 language, to permit gas utilities to recover prudently incurred interconnection investment costs in their rate base. To contain exposure, SB 919 sets two numerical limits: (1) the combined total of a gas utility’s interconnection investments and incentive awards for a single project cannot exceed the applicable per‑project cap; and (2) a utility’s annual amount of interconnection costs eligible for recovery cannot exceed 1 percent of the utility’s total authorized annual revenue requirement.
These guardrails aim to allow utility participation while bounding rate‑payer risk.Operationally, CPUC will need to adapt tariff and rate‑case processes to accommodate ratebasing interconnection work, verify prudence and direct benefits to different classes of ratepayers, track allowance revenue transfers if they are used to top up program funds, and handle project‑level accounting so the per‑project caps and the 1 percent annual limits are enforceable. The bill carries a sunset clause extension that synchronizes the program’s statutory life with the new funding and recovery provisions, meaning implementation choices made now may be temporary unless extended further by later statute.
The Five Things You Need to Know
SB 919 extends the biomethane monetary incentive program from December 31, 2026 to December 31, 2030.
The bill raises the per‑project incentive cap from $1.5 million to $3.0 million and sets a $5.0 million cap for defined dairy cluster biomethane projects (which must aggregate three or more dairies and inject through a single interconnection).
Beginning January 1, 2027, the CPUC may authorize additional program funding using revenues (and accrued interest) that gas corporations receive from the direct allocation of greenhouse‑gas allowances.
The CPUC must allow gas corporations to recover interconnection investment costs in rates, but each utility’s annual recoverable interconnection costs are capped at 1 percent of its total authorized annual revenue requirement.
For any given project, the sum of a gas utility’s interconnection investments and the monetary incentive program funding cannot exceed the applicable per‑project incentive limitation.
Section-by-Section Breakdown
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Findings and legislative purpose
This opening section sets the policy framing: climate impacts justify accelerating biomethane deployment, and allowing utilities to rate‑base interconnections can lower project costs by removing tax and financing frictions. It also asserts that excluding utility investments from the ITCCA tax factor will reduce procurement prices and benefit ratepayers—an explanatory finding the CPUC will need to account for when modeling program economics.
Directive to allow rate recovery for interconnection investments
The amended §784.2 requires the CPUC to permit recovery in rates of the specific infrastructure investments described in the section—those enabling interconnection between pipelines and biomethane generation or gathering lines—by a statutory date (June 1, 2026). It preserves the CPUC’s duty to ensure investments are prudent and provide direct benefits (safety, reliability, affordability, reduced GHGs) to all ratepayer classes, which will be the primary standard for approving any ratebasing.
Program extension and higher per‑project incentive limits
This portion extends the monetary incentive program’s effective period through December 31, 2030 and increases the per‑project monetary caps to $3 million for most projects and $5 million for dairy cluster projects. The dairy cluster definition is narrowed to projects of at least three nearby dairies that deliver biogas via multiple gathering lines to a single processing facility and single pipeline interconnection, explicitly authorizing aid for gathering lines aimed at reducing short‑lived climate pollutant emissions.
Allowance‑derived funding and numerical recovery limits
Starting January 1, 2027, the CPUC may add program funding by authorizing transfers of revenues (and interest) that gas corporations receive from the direct allocation of greenhouse‑gas allowances. The section also compels the CPUC to allow recovery of gas corporation interconnection investments, but caps exposure: annual recoverable interconnection costs per utility may not exceed 1 percent of that utility’s total authorized revenue requirement, and for any single project the utility’s investment plus program funding cannot exceed the project cap. These mechanics create enforceable ceilings tying utility recovery to existing rate‑case numbers and per‑project accounting.
Sunset and repeal date adjustments
The statute’s temporary status is updated so the relevant sections remain in force only until the new sunset date (January 1, 2031) unless further legislative action deletes or extends that date. Practically, this creates a finite window for the program and the new recovery rules unless the Legislature acts again.
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Every bill creates winners and losers. Here's who stands to gain and who bears the cost.
Who Benefits
- Dairy operators that form cluster projects — They can access a larger $5M per‑project cap that explicitly covers interconnection and gathering lines, lowering the capital barrier for aggregated manure‑to‑biomethane projects.
- Biomethane developers and aggregators — Higher caps and the possibility of utility‑led interconnections shorten timelines and reduce upfront financing costs, improving project bankability.
- Gas corporations — The bill authorizes utilities to put interconnection infrastructure into rate base, enabling cost recovery and reducing their capital risk for participating in interconnections.
- Ratepayers pursuing lower procurement prices — By removing the ITCCA tax factor on rate‑based utility investments (as the findings suggest), the bill aims to lower the delivered price of biomethane compared with non‑rate‑based procurement approaches.
- State climate policy objectives — The bill creates an avenue to scale in‑state biomethane projects that reduce methane and other short‑lived climate pollutants if projects meet program standards.
Who Bears the Cost
- Gas ratepayers — Utility investments placed into rate base are recovered through rates; the bill’s funding design shifts a material portion of interconnection costs onto ratepayers (subject to the 1% cap).
- Small or isolated RNG projects — Projects that cannot form clusters or exceed per‑project caps may face higher per‑unit costs if they cannot access the increased funding or utility interconnection support.
- CPUC and utility compliance teams — Regulators and utilities must create new tracking, prudence review, and accounting processes to enforce per‑project caps, the 1% limit, and any transfers of allowance revenues.
- State budget and allowance accounting — While not a direct General Fund cost, the use of gas corporations’ allowance revenues diverts funds tied to cap‑and‑trade allocations and requires administrative coordination that could have opportunity costs.
Key Issues
The Core Tension
The central dilemma is between lowering upfront barriers to in‑state biomethane (by letting utilities finance interconnections and by boosting incentives) and protecting ratepayers from subsidizing projects whose benefits are uncertain; the bill eases project finance but shifts definitional, prudence, and funding risks onto regulators and ratepayers.
SB 919 stitches together three levers—higher monetary caps, allowance‑derived supplemental funding, and utility ratebasing—to accelerate biomethane deployment. Each lever creates implementation questions.
Using gas corporations’ allocated allowance revenues depends on a predictable stream of such revenues and clear accounting rules to avoid double‑counting or misallocating funds; allowance flows can vary with market conditions and policy changes, so program funding could be volatile. The bill’s per‑project caps and the 1 percent annual cap are blunt instruments: they bound exposure but may be too tight for large, capital‑intensive projects or conversely too loose if not paired with strict prudence and benefit tests.
The statute requires CPUC to find that investments directly benefit all classes of ratepayers, but it leaves significant discretion about how to measure that benefit. That creates the risk of subjective prudence determinations, increased litigation, or regulatory delay.
The dairy cluster definition opens useful economies of scale but also invites structuring risks—developers may reconfigure supply arrangements to qualify for the higher cap without achieving the intended emissions reductions or community benefits. Finally, because the program is temporary (sunset extended but still finite), project sponsors and utilities face policy‑risk from potential nonrenewal, which could compress investment horizons and affect financing terms.
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