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14 min read PRIME Plus

April 30 CPUC Voting Meeting Preview: RNG Retreat, Hydrogen Denial, PG&E Financing Test

The CPUC's April 30 business meeting could produce decisions impacting utility finances, hydrogen, biomethane mandates, wildfire cost allocation, DER data, and retail bill relief. Below are some items that merit close attention.

  • A PD approving settlements in SCE's 2024 GRC Phase 2;
  • A successor docket for the CPUC's Risk-Based Decision-Making Framework;
  • A PD cutting California's biomethane procurement target in half; and
  • A PD denying SoCalGas's request to recover $266 million to fund Angeles Link Phase 2 work.

SCE 2024 GENERAL RATE CASE PHASE 2

A proposed decision approves nine of 10 settlement agreements resolving SCE's 2024 General Rate Case Phase 2 on marginal costs, revenue allocation, and rate design. The PD denies a Vehicle-to-Grid Rate Proposal Settlement Agreement and declines to adopt three contested proposals (deferring PRIME Plus and baseline allowance expansion to future rulemakings, and finding the Solar Energy Industry Association's transmission marginal cost proposal outside the proceeding's scope).

The PD adopts a comprehensive settlement on marginal cost methodology and revenue allocation, agreed to by utilities, consumer advocates, and large customer groups. It sets key cost inputs (a $132.72/kW-year generation capacity marginal cost, Avoided Cost Calculator-based energy costs, and Real Economic Carrying Charge-based customer costs) and uses these to allocate SCE's revenue requirement across customer classes.

The settlement applies a revenue-neutral allocation framework built on an illustrative $17.5 billion consolidated revenue requirement (approximately $17,466 million as of October 2024), with rates ultimately updated to actual authorized revenues at implementation. To limit bill volatility, the PD introduces "collars" that constrain how far class revenues can move from current levels: +4.0%/−6.0% for delivery revenues around the System Average Percentage Change, and +0.97%/−1.9% for generation revenues for bundled service customers.

  • A major element is the treatment of wildfire-related costs, which are allocated using a hybrid formula: 21.5% tied to distribution cost causation and 78.5% spread broadly based on system revenues, balancing cost causation with rate stability. The formula will be updated annually and governs until the next GRC Phase 2 proceeding.
  • The V2G settlement was the only opposed agreement, with Cal Advocates arguing that using the Avoided Cost Calculator to set EV export compensation is premature. The ALJ agrees, finding that the CPUC has not sufficiently evaluated the accuracy of Avoided Cost Calculator-based versus real-time marginal-cost-based credits, customer behavior regarding export rates, or export flexibility under different compensation structures. Existing dynamic pricing pilots should be used until that evaluation is complete, which portends broader implications for the Avoided Cost Calculator's expanding role in ratemaking.
  • On residential rate design, the approved settlement establishes a four-year glide-path moving Time-of-Use period rate differentials toward 80% of settled marginal cost ratios, with adjustments occurring each October 1 from 2026 through 2029. The TOU-D-PRIME seasonal differential increases from 2.4 to 6 cents/kWh, moving toward 100% of marginal cost levels over the same period.
  • SCE's PRIME Plus proposal (a demand-based residential rate variant) was not rejected on its merits. The PD defers it to an anticipated industry-wide rulemaking on residential Time-of-Use rate structures, preserving the concept for future consideration.
  • TURN's baseline allowance proposal raised a substantive issue: residential solar adoption is depressing metered usage and thereby shrinking baseline quantities, disproportionately harming non-Net Energy Metering customers. The ALJ acknowledges the problem but rules that the statutory definition of "residential consumption" under the Public Utilities Code refers to utility-delivered energy, not customer-generated energy. The issue was referred to a future rulemaking affecting all large electric investor-owned utilities.
  • The Economic Development Rate settlement raises the EDR discount from 12% to 20%, increases the MW cap from 200 to 300 MW, expands the small customer demand threshold from 150 kW to 200 kW, and includes a limited Economic Development Rate program for host sites supporting the 2028 Olympic Games.

INSTANT ANALYSIS: The PD carries four main implications.

  • Cost causation loses to rate stability (by design). The collaring mechanism and System Average Percentage Change-heavy wildfire allocators blunt large redistributions.
  • Wildfire costs are being socialized. The 78.5% System Average Percentage Change weighting spreads most wildfire burden broadly across load. This reduces class-specific exposure, especially for distribution-intensive customers.
  • The Avoided Cost Calculator's role in ratemaking is now contested ground. The V2G rejection suggests that the CPUC is not prepared to extend Avoided Cost Calculator-based compensation beyond the Net Billing Tariff without further study. Parties pushing Avoided Cost Calculator-derived values into new rate structures (dynamic rates, export credits, marginal cost proceedings) now face a higher evidentiary bar.
  • A playbook for the next GRC cycle. The settlement governs allocation mechanics until the next Phase 2. Future battles will shift from methodology to inputs: load forecasts, revenue requirement, and program costs. The baseline allowance and PRIME Plus deferrals ensure those fights will also play out in parallel rulemakings.

RISK-BASED DECISION-MAKING FRAMEWORK

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

The proceeding has four objectives:

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.

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 surfaces: California has spent a decade building tools for quantifying utility risk without ever specifying how much unmitigated risk is acceptable.

The RAMP reform track looks administrative but isn't: more formalized SPD review time means more SPD influence over what enters the GRC record. The Benefit-Cost Ratio track is where methodology becomes money: inconsistent O&M treatment means two utilities can propose functionally similar programs and score them differently based on accounting choices.

BIOMETHANE

A proposed decision cuts California's biomethane procurement target in half and pushes compliance out five years, from 72.8 Bcf annually by 2030 to 36.4 Bcf annually by 2035. The 17.6 Bcf Diverted Organic Waste target is preserved but also extended to 2035, collapsing the prior short-term/medium-term structure into a single deadline.

  • All feedstocks may bid into utility solicitations immediately, without first satisfying the Diverted Organic Waste milestone. A new Cost Containment Mechanism bars procurement approval if contracts would push the program's running-average above-market cost past 1% of the Renewable Gas Cost Allocation Pool (RGCAP) revenue requirement, or cause year-over-year increases above 3% of the prior year's combined RGCAP plus above-market cost base. The PD grounds the pullback in CARB data showing residential and commercial gas customers generated only 2.6% of statewide methane emissions in 2023.
  • The 2040 delivery cutoff is eliminated, freeing 15-year contracts signed in the late 2020s and 2030s to run their full term. Co-digestion must now separate component feedstocks for attribution rather than count wholesale as Diverted Organic Waste, reshaping dairy/food-waste project math.
  • Utilities may purchase brown gas at or below market rate from Renewable Gas Standard-eligible projects stripped of environmental attributes, with developers retaining the Renewable Thermal Certificates (a parallel transaction channel outside the Cost Containment Mechanism).
  • Open landfills become eligible contingent on a Utility Tier 2 Advice Letter coordinated with CalRecycle. Wastewater treatment plants get a narrow combustion carve-out, filtration-conditioned. The 4% livestock cap holds. Renewable Thermal Certificate unbundling and interconnection rate-basing are deferred.
  • All procurement contracts move to Tier 2 Advice Letter review, replacing the $17.70/$26.00 MMBtu price-tiered structure from a 2022 decision (D.22-02-025).

INSTANT ANALYSIS: The original Senate Bill 1440 framework ran ahead of market reality. Supply was thin, pricing was high, and the utilities were procuring into a nascent market with ratepayers bearing the risk. Halving the target and extending the deadline restores economic credibility without formally abandoning the program.

The Cost Containment Mechanism is notable. A hard affordability screen tied to running-average and year-over-year bill impact suggests that procurement will survive only if the numbers pencil. Expect suppressed high-priced RNG contracting, reduced speculative bidding, and leverage shifting from developers who assumed mandated demand would guarantee premiums.

Opening feedstock eligibility is a pragmatic pivot toward commodity sourcing, but the retained Diverted Organic Waste target plus co-digestion attribution changes keep the Senate Bill 1383 linkage intact.

For gas utilities, this PD brings relief. For Renewable Natural Gas developers, policy support now comes with stricter economics and cost containment. For large customers, the PD suggests that the Commission will revisit climate programs when affordability pressure becomes difficult to ignore.

A proposed 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 PD 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 PD notes this means no federal offset exists for the proposed costs.
  • The PD 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 PD 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 PD 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 PD 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

This proposed decision conditionally approves PG&E's request under Public Utilities Code Section 851 to lease interests in future transmission projects to Citizens Energy Corporation. The arrangement would allow Citizens to provide up to $1 billion in prepaid capital across five option periods in exchange for 30-year leasehold entitlements in qualifying PG&E high-voltage transmission assets, with Citizens receiving a proportionate share of CAISO Transmission Access Charge revenues.

  • The PD does not grant blanket approval. PG&E must file a Tier 3 Advice Letter for each option period identifying specific projects and demonstrating that ratepayers are no worse off than under ordinary utility balance-sheet financing. The PD finds the overall structure novel enough to warrant heightened public-interest review, citing undefined future projects and unknown revenue requirements across all five tranches.
  • Citizens has committed to directing a large share of after-tax profits to customer bill assistance in PG&E territory, estimated at more than $450 million over the life of the program. The PD finds the current record insufficient on distribution mechanics. Each advice letter must detail participating nonprofits, eligible communities, demographics served, and alignment with CPUC environmental and social priorities. For Option Periods 2 through 5, PG&E must also account for how funds were actually spent in the prior period.

INSTANT ANALYSIS: This decision rejects the broad financing pipeline PG&E sought and converts it into a tranche-by-tranche approval regime. The deeper theme is institutional caution around off-balance-sheet utility finance: the CPUC is open to alternative capital sources for transmission buildout but unwilling to delegate future oversight based on a high-level framework.

For PG&E, conditional authority is still optionality. If balance-sheet pressure or transmission build demands intensify, it now has a pathway to monetize portions of future transmission assets. For ratepayers and consumer advocates, the ruling preserves repeated intervention points and forces proof that outside capital is at least competitive with traditional utility financing at each exercise.

DISTRIBUTED GENERATION

Draft Resolution E-5436 expands funding and governance for the California Distributed Generation Statistics (DGStats) platform, raising the three-year contract cap from $990,000 to $2.6 million, with annual inflation indexing authority delegated to staff.

The draft resolution frames DGStats as a nationally recognized repository underpinning Integrated Energy Policy Report forecasting, NEM/NBT cost-shift analysis, and DER program design. PG&E, SCE, and SDG&E must also rebrand the platform under a broader name that can accommodate non-DG programs like Community Solar.

Draft Resolution E-5436 orders a sweeping cleanup of interconnection data systems:

  • Validated equipment drop-downs for generators, inverters, and batteries;
  • Standardized language and validation rules on system-cost entries; renaming "System Size" fields to "Generator Size" (DC and AC);
  • Auto-calculation of DC capacity in Standard Test Condition; and
  • Retroactive rebuilding of historical DC entries where equipment matches the verified list.

Energy Division attributes current data problems to manual inputs, inconsistent test conditions, and placeholder cost entries like $0 or $1 submitted to speed through review.

The utilities must host a hybrid public stakeholder workshop on decommissioning, covering the prevalence of unreported decommissions, metering-based detection, customer guidance, and Integration Capacity Analysis and forecasting impacts. They must also begin tracking standardized decommission reasons (Replaced, Retired functional/non-functional, Destroyed, Abandoned, Other) in a queryable format. Separately, Energy Division is authorized to publish anonymized CSLB Disclosure Document data on DGStats.

INSTANT ANALYSIS: A 2.6× funding increase shows sustained institutional investment in distributed resource intelligence, and the CPUC is treating DER data as planning infrastructure. The most consequential piece of the draft resolution is data normalization. Retroactive DC capacity corrections, stricter cost-entry validation, and standardized equipment inputs could greatly improve the datasets feeding NEM/NBT cost-shift debates, California Energy Commission demand forecasting, and hosting-capacity analysis.

Decommissioning (the permanent retirement of an interconnected DG system) deserves attention. Regulators appear concerned that aging and abandoned systems are overstating active DER capacity in Integration Capacity Analysis maps and planning models, meaning some distribution upgrades may be sized against phantom generation. If the workshop confirms the scale, it will reopen questions about hosting capacity claims and DER penetration figures that have shaped recent proceedings.

Every forecast, cost-shift model, and hosting-capacity map downstream of DGStats inherits whatever the cleanup produces.

CLIMATE CREDIT

A proposed decision in R.25-07-013 directs immediate, interim changes to California's residential Climate Credit program to improve bill affordability, primarily by shifting when credits are delivered rather than altering their size or eligibility.

Historically, these credits (funded by Cap-and-Invest allowance revenues) were issued in low-usage months (spring and fall), but the CPUC now finds that approach misaligned with affordability needs.

  • For 2026, large electric utilities (PG&E, SCE, SDG&E) are ordered to move electric bill credits to August and September, when usage and bills are highest. Small and multi-jurisdictional utilities (Bear Valley, Liberty, PacifiCorp) will shift their remaining 2026 credit to November to match winter peaks, then distribute in October and November beginning in 2027.
  • Natural gas credits will move to February beginning in 2027; the April 2026 gas credit already went out and could not be redirected, given timing constraints.
  • The PD emphasizes speed and feasibility, adopting only timing changes that utilities can implement immediately, while deferring more complex reforms (e.g., eligibility changes, credit recalculation, baseline territory-level distribution) to Phase 1B.
  • In parallel, the PD implements statutory requirements under Assembly Bill 1207 by directing electric utilities to remit 5% of Cap-and-Invest allowance auction revenues to the State Treasury for deposit in the California Transmission Accelerator Revolving Fund. Remittances are due within 15 days of final receipt of revenues from each auction, covering auctions held between July 1, 2026 and July 1, 2031.
  • The PD updates Template D-1 within the utilities' Greenhouse Gas Revenue and Reconciliation Application Form, requiring standardized reporting on remittances through existing ERRA compliance, the Energy Cost Adjustment Clause, or advice-letter filings.
  • The PD also requires limited updates to customer outreach (primarily clarifying bill savings and attributing them to the Cap-and-Invest program) while avoiding expanded messaging that could reduce available credit funds.

All changes are explicitly designated as interim, preserving flexibility for broader program redesign in subsequent phases of the rulemaking.

INSTANT ANALYSIS: If adopted, this PD would shift Climate Credits into peak months, lowering summer and winter bills without increasing total value. It's a timing change, not new relief. The bigger move is upstream: AB 1207 requires 5% of allowance auction revenues to flow to the Transmission Accelerator Fund, reducing the pool available for bill credits. The CPUC is implementing a legislative mandate, not making a discretionary policy choice, but the effect is the same. Climate funds are starting to split between direct ratepayer relief and grid infrastructure buildout. Utilities get a simple, workable change on credit timing. Affordability reforms are deferred.

ERRA COMPLIANCE

A proposed decision approves, with modifications, SDG&E's 2023 ERRA compliance filing and authorizes recovery of a net $214.580 million undercollection. This amount excludes confidential Local Generating Balancing Account and Tree Mortality Non-Bypassable Charge Balancing Account balances.

Three negotiated adjustments are adopted.

  • SDG&E's Resource Adequacy Buffer (initially treated as unsold and valued at zero) is reclassified as Retained RA, with SDG&E's own counterproposal adopted as the Consensus valuation methodology.
  • The Renewables Portfolio Standard position is corrected by $3.2 million in additional Retained RECs.
  • 2023 revenues from the Miguel Vanadium Redox Flow and Ramona Air Attack Base battery systems are booked to the Electric Distribution Fixed Cost Account, spreading benefits across all distribution customers rather than bundled customers alone.

The substantive fight involves the Green Tariff Shared Renewables program. The EcoShare sub-program never enrolled a customer; EcoChoice's enrollment collapsed into a death spiral of rising rates and departures. San Diego Community Power and Clean Energy Alliance argued that the Public Utilities Code confines recovery to former participants or shareholders. The PD rejects that reading.

SDG&E may recover outstanding Green Tariff Shared Renewables balances through the Public Purpose Programs charge, with a Tier 1 Advice Letter apportioning costs across customer classes based on historical GTSR load, with class-specific per-kWh adders applied.

INSTANT ANALYSIS: ERRA compliance proceedings keep absorbing allocation fights that exceed their nominal scope. The Green Tariff Shared Renewables mandate is the main precedent here. Once a Commission-designed program collapses and the participant class empties out, statutory indifference protections lose much of their power, and stranded balances migrate to the PPP. Other utilities will study this logic closely: when no participant class remains, cost recovery can shift elsewhere.

The PD also demonstrates the CPUC's preference for administrability over hindsight punishment. Compliance with prior CPUC direction still insulates utilities when programs fail on design rather than execution. Intervenors should read this as a warning: attacking execution is insufficient when the framework itself was Commission-built.

Cost-allocation elasticity ends up being the main story. Narrow legacy balances become broad surcharges when no clean payer class survives, which is worth tracking as load migration and non-bypassable charge pressure continue to compound.

Published by:

MC

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