April 30 CPUC Voting Meeting Results: Biomethane Cut, Hydrogen Denied, Transmission Financing Opens

The CPUC's April 30 voting meeting featured major moves on RNG, hydrogen, transmission financing, electric rates, and risk-based decision-making.

BIOMETHANE

A decision rebuilds the CPUC's Renewable Gas Standard around a hard cap on what ratepayers can be charged, not the volume targets that drove the original program. Two tests now gate every new contract:

• Above-market costs can't exceed 1% of core customer revenue requirements on a running-average basis; and
• They can't grow more than 3% in any single year.

Failure of either test means the CPUC won't approve the procurement.

Procurement volume targets are halved and stretched. What was 72.8 Bcf by 2030 is now 36.4 Bcf by 2035. The 17.6 Bcf Diverted Organic Waste (DOW) target survives intact and shifts to the same 2035 deadline. Non-DOW procurement absorbs the entire reduction. Contracts can now extend past 2040, though the 15-year length cap stays. Every feedstock is eligible immediately, and co-digestion projects have to attribute biomethane to each component feedstock separately rather than count the full output as DOW.

Elsewhere, open landfills can now participate in the program, pending a utility proposal that addresses the incentive to accept more organic waste once a landfill is earning biomethane revenue. Wastewater treatment plants taking Diverted Organic Waste get a combustion exception for existing capacity, with filtration and full lifecycle carbon accounting required. Utilities can buy plain old biomethane from RGS-eligible projects at market rate while developers keep the environmental attributes (those volumes don't count toward targets or the cap). Broader unbundling will be examined in the future. The decision denies interconnection ratebasing, but a workshop and application pathway are on the calendar.

Commissioner Comments from the Dais

• President John Reynolds framed the decision as a course correction, noting that California's biomethane market remains nascent and that current affordability pressures require stronger cost containment.
• Commissioner Christine Harada argued that climate impact alone cannot be the sole lens for evaluating the program; the Commission's role as economic regulator requires that costs be allocated fairly and sustainably.
  • Harada pointed to rising utility bills driven by the financing of safety and climate investments through rates, and stated that ratepayers cannot serve as an open-ended funding source. She described the procurement target reduction as a calibration to present market conditions, arguing that advancing procurement ahead of market development would impose higher costs without efficiency gains.
• Harada added that biomethane produced in-state from existing waste streams reduces dependence on Permian and Rockies imports and mitigates exposure to price volatility and supply disruptions.
• Harada acknowledged party concerns about double-counting under the original unbundling framework and explained the reversal: utilities must now purchase and retire environmental attributes to receive full credit, with future proposals on separately valuing upstream avoided emissions to come back via the advice-letter process.
• Commissioner Darcie Houck articulated the Cost Containment Mechanism in operational terms: the 1% cap measures average customer cost increases from the program's 2022 inception. The 3% cap prevents rate shock by limiting any single year's increase.
  • Houck cited the high variance between market cost and current Renewable Gas Standard contract costs as the reason the containment measure is necessary.
  • Houck identified the interconnection ratebasing sequence as a meaningful ratepayer protection: utilities must first secure approval of a Tier 3 advice letter via resolution before they can file an application to ratebase interconnection costs. And any application must demonstrate meaningful cost reductions to ratepayers.

INSTANT ANALYSIS: In essence, this decision admits that the CPUC's original 2022 program design didn't take ratepayer impact seriously enough. For utilities and large gas buyers, the threat of being forced into expensive contracts to hit unreachable targets is gone. The DOW target held while the overall target was cut in half. That's the CPUC saying Senate Bill 1383 waste diversion is what this program is actually for, and the rest of the volume was aspiration the CPUC is willing to abandon.

HYDROGEN/ANGELES LINK

A decision denies SoCalGas's request to recover $266 million from natural gas ratepayers to fund Phase 2 front-end engineering and design work for the Angeles Link hydrogen pipeline project.

The project entails dedicated hydrogen transmission pipelines to deliver renewable hydrogen into the Los Angeles Basin for hard-to-electrify sectors including power generation, industrial uses, and heavy-duty transportation. The decision finds that the project remains speculative, with no specific customer base identified – as required by a 2022 decision (D.22-12-055) – no guarantee of construction, and no demonstrated direct benefits to existing natural gas ratepayers.

• The record shows significant opposition from consumer advocates, environmental groups, and shippers, who argue that the project's benefits are indirect and uncertain, and that shifting early-stage development costs onto ratepayers would violate core cost-causation principles. Phase 2 cost estimates have nearly tripled since the project was initially proposed, rising from $92 million to $266 million.
• SoCalGas declined federal IIJA funding through ARCHES ( funding the CPUC had specifically directed the utility to pursue in D.22-12-055 to offset ratepayer exposure) arguing that federal compliance costs would not serve ratepayer interests. The decision notes this means no federal offset exists for the proposed costs.
• The decision concludes that ratepayer funding is not justified at this stage, emphasizing that the project is still in planning, has seen cost estimates rise sharply, and lacks clear alignment with established standards requiring projects to be "used and useful" before cost recovery. The decision does not adopt TURN's alternative proposal to track Phase 2 costs in a memorandum account for future recovery once the project becomes operational.
• The decision declines to resolve jurisdictional questions around whether the project would qualify as a pipeline under Public Utilities Code Section 227/228 or a gas plant under Section 221/222, finding such determinations both premature (because the project is not constructed or dedicated to public use) and unnecessary given the denial of cost recovery. The application is denied in full and the proceeding is closed, leaving SoCalGas to pursue the project, if at all, without ratepayer-backed funding for Phase 2.

INSTANT ANALYSIS: The CPUC is rejecting the idea that speculative, pre-construction hydrogen infrastructure can be funded by legacy gas ratepayers, though it is not permanently foreclosing ratepayer recovery if the project is eventually constructed and demonstrated to be used and useful. For now, the decision is pushing hydrogen out of the mainstream utility cost-recovery model and into a merchant or contract-backed lane. The refusal of federal funding compounds the problem: SoCalGas eliminated the one mechanism the CPUC itself identified to cushion ratepayer impact, then asked ratepayers to absorb the full cost anyway. Developers will need anchor customers, bilateral deals, or external capital.

TRANSMISSION

A decision, which carried 4-1 (Commissioner Darcie Houck dissented) conditionally authorizes PG&E to lease transmission "entitlements" to a Citizens Energy subsidiary but approves no specific transaction. PG&E may file up to five Tier 3 Advice Letters over a five-year window, each covering a tranche of defined transmission projects and each tested against traditional utility financing.

Within each tranche, Citizens prepays for up to a 49.9% leasehold share, collects CAISO transmission revenues over 30 years, then returns the assets. The five tranches are capped at $1 billion in aggregate, averaging $200 million each. PG&E builds, owns, and operates throughout.

The decision applies a heightened public-interest standard given the scale and undefined nature of the projects. Energy Division can refer any Advice Letter to a full application proceeding. PG&E must also file Tier 1 Advice Letters when FERC approves a new formula rate, showing how the updated model would differ from Citizens' locked-in terms.

Citizens commits an escalating share of net after-tax profits to direct bill assistance (50% on the first tranche scaling to 90% on the fifth) projected above $450 million total. Citizens also forgoes recovery of its own administrative costs, a concession the decision distinguishes from the Sycamore deal (a 2019 Citizens-SDG&E transmission lease that serves as the closest precedent). Each Advice Letter must name delivery organizations, targeting criteria, demographic reach, and 501(c)(3) channeling, with retrospective accounting before later tranches.

Attached data-field appendices require tranche-level disclosures on cost evolution, ratepayer allocation, and revenue-requirement modeling.

Commissioner Comments from the Dais

• Commissioner Matthew Baker characterized the deal as PG&E exchanging decades of future transmission revenues and profits for upfront capital that is useable today. Baker cited PG&E's low share price and below-investment-grade ratings as making traditional market access "very, very difficult," and noted that Citizens' payments are not recorded as debt or equity and consequently do not affect PG&E's capital structure or credit profile.
  • Baker pointed to wildfire costs as the main driver pushing PG&E toward novel financing, and cited the legislature's recently enacted Transmission Infrastructure Accelerator as part of a longer-term solution.
• Commissioner Christine Harada acknowledged PG&E's progress since bankruptcy but described the company's financial position as "structurally fragile" relative to its peers, and explicitly disclaimed any view that this decision constitutes bailing out PG&E.
  • Harada framed the approval as a one-time, fact-dependent framework specific to PG&E's unique and "hopefully temporary" financial situation, not a model for future requests.
• President John Reynolds tied his support to the ratepayer benefit story, noting the escalating profit-share structure (50% on Tranche One, rising to 90% on Tranche Five) and the over $450 million in projected bill assistance.

In dissent, Commissioner Houck argued that the Public Utilities Code and General Order 173 require a formal application for utility property transactions exceeding $5 million, and that approving roughly $1 billion of leases through five Tier 3 Advice Letters does not meet the required legal standard.

Houck cited TURN's estimate that ratepayers could save roughly $740 million across the five tranches by financing through securitized debt instead of the proposed lease structure, and argued the proceeding lacks any real assessment of ratepayer cost. She recommended denying the application without prejudice, or holding the proceeding open for a supplemental application.

INSTANT ANALYSIS: This decision opens a new transmission financing lane under strict supervision, but the economics are contested. TURN placed Citizens' implied annual return above 9% versus PG&E's projected 6.0%-to-6.5% cost of new long-term debt. Citizens itself conceded a 6.93% return would clear lender requirements. The decision does not cap the return, but the concession is preserved and will reappear at every tranche review.

$450 million in bill assistance is what makes the deal politically viable. Without it, the CPUC would be approving an above-market return for a non-utility investor during an affordability crisis.

Two provisions give the CPUC room to reverse course. The CPUC may revisit necessity if PG&E's credit rating returns to investment grade. And Cal Advocates has formally contested the premise that PG&E cannot self-fund, meaning intervenors can reopen the necessity question at every tranche.

SCE GENERAL RATE CASE PHASE 2

A decision resolves SCE's 2024 rate-design case. The decision approves nine of 10 settlements that parties negotiated and rejects the tenth, a Vehicle-to-Grid rate proposal. The decision also rejects three contested proposals that didn't make it into settlements:

• SCE's PRIME Plus rate;
• A baseline allowance increase pushed by TURN; and
• A transmission marginal cost methodology pushed by the solar industry.

New rates take effect no earlier than October 1. The settling parties get a four-year transition that lifts residential Time-of-Use price differentials to 80% of marginal cost, except PRIME, which goes to 100%. Recall that PRIME is the rate aimed at households running heat pumps, electric vehicles, and storage. Its seasonal differential jumps from 2.4 cents to 6 cents per kilowatt-hour, and its peak-to-off-peak price ratio reaches full marginal cost by year four. Generation capacity costs are set at $132.72 per kilowatt-year. Generation energy values are taken from the 2024 Avoided Cost Calculator.

Wildfire cost recovery is the most consequential piece for class-allocation work. About three-quarters of the wildfire revenue requirement is allocated to customer classes in proportion to the revenue they already pay, meaning residential picks up a residential-sized share, large power picks up a large-power-sized share, etc. The remaining quarter is allocated based on each class's actual use of the distribution system, where most wildfire mitigation spending occurs. The allocation gets redone every year using updated sales, customer counts, and class revenue shares, so the percentages each class pays will drift over the term of the settlement.

Large power customers receive continuity. The settlement keeps Option D and Option E intact across voltage tiers and sets the monthly customer charges directly: $1,140.50 for TOU-GS-3, $2,514.50 for TOU-8 secondary, $313.25 for primary, $8,512.50 for subtransmission. On electric vehicles, the settling parties agree that any rate changes taking effect after 2030 should be decided in a different proceeding, and that proceeding should ideally cover PG&E and SDG&E too so the three utilities don't end up with three different EV rate structures.

INSTANT ANALYSIS: The CPUC is using the Avoided Cost Calculator selectively. It accepted the calculator as the source for generation energy values in the main settlement, then two settlements later rejected using it to set EV export compensation, agreeing with Cal Advocates that forecasted averages can't capture real-time or locational grid conditions. The CPUC seems comfortable using the calculator for embedded cost recovery but unwilling to use it as a price signal for customers selling power back. The list of evaluations the CPUC wants done first on Vehicle-to-Grid tells you where it's heading on export compensation generally.

Three of the four rejections aren't substantive losses, they're forum punts. PRIME Plus moves to the rate rulemaking the CPUC just opened (R.26-04-009). The transmission marginal cost question moves to the cost study already underway, aimed at the 2028 update cycle. TURN's baseline argument got a genuine concession buried in the rejection: the decision agrees that, as more customers install rooftop solar, SCE's measure of average residential usage keeps dropping, which shrinks the baseline allowance for everyone else (even though their actual energy needs haven't changed). The decision says a solution belongs in a rulemaking encompassing all three electric utilities.

RISK-BASED DECISION-MAKING FRAMEWORK

A successor docket, launched today, will continue refining the Risk-Based Decision-Making Framework that governs how utilities propose safety spending in General Rate Cases.

The proceeding has four objectives:

• Incorporating a formal risk tolerance standard into the framework;
• Modifying the Risk Assessment & Mitigation Phase schedule to give the CPUC's Safety Policy Division more review time;
• Updating the Benefit-Cost Ratio methodology; and
• Assessing whether small gas utilities Alpine Natural Gas and West Coast Gas should be required to file annual Risk Spending Accountability Reports.

The docket's risk tolerance track picks up where D.25-08-032 left off. That decision defined risk tolerance but declined to adopt a formal standard, delegating the work here. The CPUC will seek party proposals on both a formal tolerance standard and a benchmark tied to everyday risks Californians already accept.

The RAMP schedule track responds to a documented pattern: the CPUC's Safety Policy Division has received deadline extensions on every RAMP filed since 2020, running about two months each time. The new rulemaking proposes formalizing additional review time, starting with PG&E's 2028 RAMP.

The Benefit-Cost Ratio track addresses two gaps:

• Inconsistent utility treatment of O&M expenses; and
• A Present Value Revenue Requirement field that is currently optional but may be made mandatory. A parallel joint application (A.26-02-005) on Benefit-Cost Ratio methodology for the Senate Bill 884 undergrounding program may inform this work.

Commissioner Comments from the Dais

• President John Reynolds highlighted four focal areas: a risk tolerance standard, extended RAMP review timelines, standardized O&M treatment/data requirements, and expanded RSAR reporting. He noted that a 2025 decision (D.25-08-032) deferred the risk tolerance question, making this proceeding the vehicle to resolve it. Reynolds also connected the framework directly to future cost recovery, including programs like Senate Bill 884 undergrounding.
• Commissioner Darcie Houck warned against "risk reduction at any cost,” noting that zero risk is unattainable. She encouraged the integration of existing affordability metrics into Benefit-Cost Ratio analyses for more granular ratepayer impact assessment.
• Commissioner Christine Harada broadened the risk landscape beyond wildfires to include floods, cybersecurity threats, and pipeline failures.
  • Harada supported the concept of a risk-tolerance standard, drawing parallels to engineering disciplines that operate within defined “risk envelopes."
  • Harada emphasized that limited budgets require explicit tradeoffs rather than implicit escalation of spending.
  • Harada suggested the Risk-Based Decision-Making framework can improve decision-making by defining acceptable risk ranges rather than pursuing absolute minimization.

INSTANT ANALYSIS: Framework proceedings move slowly and attract less attention than contested rate cases, but their outputs are load-bearing. The risk-tolerance track is where the hardest policy question will surface: California has spent a decade building tools for quantifying utility risk without ever specifying how much unmitigated risk is acceptable.

CLIMATE CREDIT

A decision orders interim, timing-only changes to the residential Climate Credit, reserving amount, eligibility, and calculation for Phase 1B of this proceeding. The statutory basis for the decision is Assembly Bill 1207's amendment to Public Utilities Code, which requires distribution in no more than four high-billed months annually.

PG&E, SCE, and SDG&E will distribute the electric credit in August and September beginning in 2026. A March decision (D.26-03-013) paused the April distribution to enable this. The Small and Multi-Jurisdictional Utilities will distribute the credit in November 2026, then October and November in 2027 (one credit is retained in October because seasonal load variation in those territories is less pronounced). Gas utilities will move to a single February distribution, beginning in 2027.

The decision also redirects 5% of allowance auction revenues from ratepayer return to transmission financing, implementing AB 1207's Transmission Accelerator Revolving Fund provision. Remittances to the State Treasury run from July 1, 2026 through July 1, 2031.

INSTANT ANALYSIS: The Climate Credit is no longer a complete pass-through to ratepayers. Five percent being redirected to transmission financing for five years is modest in dollars but precedential. AB 1207 extended Cap and Invest through 2045, and the CPUC has established that allowance revenues are available for appropriation toward adjacent purposes. Distribution upgrades, wildfire mitigation, and DER buildout are the obvious next targets.

The timing change supplants the price-signal rationale with a bill-offset rationale. The CPUC's 2014 and 2018 designs placed credits in shoulder months to preserve conservation incentives and maximize per-bill visibility. But now, immediate affordability takes precedence.

ERRA COMPLIANCE

A decision approves SDG&E's 2023 ERRA compliance application, finding the utility's procurement, dispatch, contract administration, and accounting practices reasonable and consistent with CPUC standards, with a net undercollection of $214.6 million.

The decision adopts three negotiated corrections developed with intervenors:

• Updates the valuation of retained Resource Adequacy;
• Corrects the Renewables Portfolio Standard position; and
• Books 2023 revenues from the Miguel Vanadium Redox Flow and Ramona Air Attack Base battery systems to the Electric Distribution Fixed Cost Account, rather than a generation balancing account that would have flowed only to bundled customers.

Most issues were resolved without dispute. Cal Advocates secured one operational directive: SDG&E must consult with intervenors on data-request quality from its new settlement system, a requirement likely to carry over to other utilities operating new settlement platforms.

The decision declines to resolve allocation of stranded costs from the failed Green Tariff Shared Renewables programs, finding the record insufficient to determine whether costs should be borne by all ratepayers, former participants, or shareholders. This marks a reversal from the original February 13 proposed decision, which would have authorized recovery from all ratepayers via the Public Purpose Program charge.

Following Rule 14.3 comments from San Diego Community Power and Clean Energy Alliance, an April 22 revised PD removed all GTSR findings and substituted an "insufficient record" determination. In a subsequent ex parte communication, SDG&E sought reinstatement of the original approach, arguing the record supported socialized recovery and that the revision deleted supported findings without explanation. Thursday's final decision adopts the revised treatment and leaves the issue open for further proceedings.

INSTANT ANALYSIS: This decision punts on GTSR cost allocation. SDG&E loses both a clean recovery path and the underlying prudence findings that would have shaped future GTSR cycles, while the CCAs secure removal of adverse findings without yet winning on the merits. The cost-allocation dispute now resets on an open record, with a statutory question (whether the CPUC can socialize GTSR costs to non-participants at all) back in play. All three pathways remain viable: recovery from all ratepayers, recovery from former program participants, or absorption by shareholders. This will return as a focused dispute with real rate impacts.

DISTRIBUTED GENERATION

Resolution E-5436 raises the DGStats budget from $990,000 to $2.6 million per three-year cycle and delegates annual inflation adjustment to Energy Division. The existing $990,000 remains in current General Rate Cases; the $1.61 million increment will be tracked through memorandum accounts and recovered in each utility's next rate case (SDG&E Test Year 2028, SCE TY 2029, PG&E TY 2031).

PG&E, SCE, and SDG&E must update their online interconnection application interfaces with:

• Validated drop-down menus for generators, inverters, and batteries;
• Auto-calculated System Size (DC) values in Photovoltaics for Utility Scale Applications Test Condition; and
• Standardized language and data validation rules for the Total Cost field.

Applicants will provide the inputs; the utilities will implement the interface controls. The resolution is emphatic that utilities are not responsible for verifying cost data accuracy.

Decommissioning is a new focus area. The utilities must begin reporting standardized decommissioning reasons (Replaced, Retired-functional, Retired-non-functional, Destroyed, Abandoned, Other) to DGStats.

Energy Division is authorized to publish a limited set of CSLB Disclosure Document fields on DGStats: ownership structure (Power Purchase Agreement/lease vs. purchase), total system cost for cash and loan transactions, and battery capacity. These were selected because they already appear in the public interconnection dataset, which is also why the CPUC concluded a Primary Purpose declaration under D.11-07-056 was unnecessary.

The CPUC, not the utilities, will rename the DGStats platform after SDG&E argued branding falls within Commission jurisdiction.

INSTANT ANALYSIS: The utilities lost. They tried to push data-quality directives into R.25-08-004, the distribution-level interconnection rulemaking, where they would have years to litigate them. SCE argued the CPUC can't even do staff resolutions like this. PG&E said its IT team needed more time. SDG&E said the cost field changes overstepped Rule 21's purpose. Resolution E-5436 rejects the venue argument, gives PG&E a 60-day extension, and adopts the data-quality directives, decommissioning workshop, and CSLB publication authority over utility objections.

Interconnection interfaces (long treated by utilities as their own technical territory) are now subject to Energy Division specification on equipment lists, cost field language, and system size calculation methods. The Commission's hope is that future data will become cleaner, more standardized, and harder to argue about, which changes who has the better numbers in debates about NEM cost shifts, DER penetration, and procurement need.