April 9, 2026 CPUC Voting Meeting Results: Commission Launches Rate-Design Overhaul as Wildfire Costs, Data Centers, and Income Tiers Collide

The CPUC convened for its April 9 voting meeting. As we anticipated yesterday, three notable items were held by the Commission until its April 30 meeting:

• BIOMETHANE: A proposed decision modifying the CPUC's Renewable Gas Standard program under Senate Bill 1440;
• TRANSMISSION: A PD allowing PG&E to enter into a long-term investment arrangement with Citizens Energy Corporation; and
• ERRA COMPLIANCE: A PD approving SDG&E's 2023 Energy Resource Recovery Account compliance application.

Below are summaries and analyses of today's most substantive agenda items. The meeting oversaw the launch of a significant rate-design rulemaking, new compliance requirements for interconnection data, and an energy-storage investigation.

ELECTRIC RATE DESIGN

The Commission launched a new rulemaking on advanced electric rate design, focused on cost causation, affordability, and clearer price signals for grid use, covering both residential and non-residential rate structures. The proceeding carries forward unresolved issues from the Demand Flexibility rulemaking (the Base Services Charge, dynamic rates, and electrification incentives) and implements two new statutory requirements:

• A data-center cost impact assessment due to the Legislature by January 1, 2027; and
• An exemption from non-bypassable charges for certain industrial customers using process heat recovery technology (Assembly Bill 2109).

A proposed consultant scope expands the Commission's rate-design modeling infrastructure and adds a new toolkit for large non-residential customers. Parties will be able to model bill impacts across Time-of-Use periods, demand charges, and major cost drivers including transmission and wildfire costs.

Wildfire-related costs are now central to rate design. Authorized costs between 2019 and 2024 total approximately $40 billion (about 27% of PG&E's total revenue requirement and 17% of SCE's and SDG&E's), which is currently recovered through volumetric rates.

An Income Verification Process Working Group report proposes a framework for differentiating among non-low-income customers (those who do not qualify for CARE or FERA) by subdividing them into separate moderate- and high-income tiers using census tract data. A customer appeals process would handle exceptions. The Commission is also considering an alternative design that would place all non-low-income customers in the highest tier by default, requiring them to appeal downward to receive a lower rate.

COMMENTS FROM THE DAIS: President John Reynolds framed rate design as the primary interface between ratepayers and California's policy goals: well-designed rates advance the transition, poorly designed ones work against it.

• Commissioner Matthew Baker said existing methods are "deeply unequal" and breaking down under wildfire costs embedded in volumetric rates. He noted Fresno, where PG&E customers are running $40–$100/month above average in summer, with the lowest wealth quintile spending as much as 75% of discretionary income on electricity after rent.
  • Baker named this as a direct consequence of how wildfire costs are currently collected.
  • Baker also acknowledged data-center load growth as a potential source of system value, not just a cost-shifting risk.
• Commissioner Christine Harada framed rate design as the incentive layer determining whether infrastructure investment realizes its value, emphasizing modernized price signals, accessible demand flexibility, and equitable benefit distribution.
• Commissioner Darcie Houck said that the affordability crisis is rooted in asking rates to solve problems that ratemaking is ill-equipped to solve, with wildfire mitigation costs being the prime example. She characterized the current recovery structure as unsustainable given that the benefits accrue to the state as a whole (rather than ratepayers alone).
  • Houck raised the possibility of moving these costs out of rates entirely and pointed to the new Senate Bill 254 report as carrying legislative recommendations the CPUC will need to coordinate with externally.
  • Houck also broadened the affordability lens to the large population of Californians for whom the rate itself is the only available mitigation tool, called out tribal communities as requiring proactive engagement.
  • Houck closed by highlighting demand flexibility as an underutilized tool that the rate structure should be explicitly designed to accommodate.

INSTANT ANALYSIS: This OIR is a major reset. The CPUC is consolidating unresolved issues from multiple proceedings into a single venue where affordability, electrification, and large-load growth now collide. Standardized modeling tools will compress input disputes; the real fights will be over methodology, cost-allocation assumptions, and who controls the analytical frame.

Four areas merit close attention.

• Wildfire cost recovery is the dominant affordability driver and may become a legislative question, not just a rate-design one. At 17–27% of utility revenue requirements and recovered entirely on a volumetric basis, any reclassification into fixed or demand charges reshapes bills for every large C&I customer on the service list. Entities with exposure to cost-recovery proceedings or legislative strategy should treat this as a question of who ultimately bears wildfire liability costs, not just a rate-design dispute.
• Large-load tariff design will be contested on two fronts simultaneously: ratepayer protection from data center cost-shifting on one side, and tariff structures that capture system value from large loads on the other. Commissioners Baker and Houck both noted the upside: large-volume consumption, correctly tariffed, could place downward pressure on rates broadly. How the Commission resolves this issue will determine whether data-center growth is net negative or net positive for the broader customer base and sets precedent for hydrogen and other large emerging loads.
• Income verification carries significant cost and misclassification risk. The proposed threshold defining "moderate income" (below 600% of the Federal Poverty Line, or $159,900 for a household of three in 2025) will be the opening salvo in party comments. The alternative design that would place all non-low-income customers in the highest tier by default would significantly alter administrative burden and customer segmentation outcomes if adopted. Commissioner Baker's Fresno data shows the gap is already wide enough that getting it wrong at scale could put more upward pressure on rates.
• Demand flexibility and dynamic rates are the execution layer uniting all three areas above. Harada telegraphed that proposals failing to credibly translate price signals into customer behavior will face opposition throughout this proceeding. Commissioner Houck reinforced it: rate structures that treat demand flexibility as an add-on rather than a design requirement are unlikely to survive Commission scrutiny.

Interconnection economics are a natural downstream consequence of how large-load rate design resolves, though not a stated scope item in this order.

INTEGRATION CAPACITY ANALYSIS

Resolution E-5440 approves, with modifications, remediation plans submitted by PG&E, SCE, and SDG&E to fix accuracy, transparency, and usability problems in their Integration Capacity Analysis tools. These tools estimate how much distributed energy can be added to the grid without upgrades.

The resolution approves PG&E's already-underway remediations for erroneous device setting data and incorrect queued generation mapping, orders SCE to complete reactivation of the remaining 311 inactive circuits on its ICA maps by September 30, directs utilities to improve the timeliness of map updates, and expands reporting so stakeholders can track when Integration Capacity Analysis results diverge from real interconnection outcomes.

• It establishes a formal concordance/discordance framework that categorizes interconnection and energization applications into one of four scenarios based on whether the ICA map value and the actual engineering outcome aligned. In so doing, the resolution creates a taxonomy for measuring ICA usefulness across all three major electric utilities.
• The resolution orders SDG&E to immediately cease excessive redactions of "Total Generation" and "Existing Generation" fields for circuits implicating the 15/15 rule and to publish those fields within 30 calendar days. It also directs all utilities to publish more complete system information (including substations up to the transmission level) on public planning portals within three months, and establishes new metrics to measure whether Integration Capacity Analysis outputs align with actual engineering results.
• The resolution codifies new definitions, distinguishing "ICA accuracy" (whether the utility correctly followed the approved methodology) from "ICA alignment" (whether ICA results match real-world engineering outcomes).

INSTANT ANALYSIS: This resolution is the Commission’s clearest move yet to turn Integration Capacity Analysis from a planning artifact into an accountability tool. By forcing the utilities to track when Integration Capacity Analysis results diverge from real interconnection outcomes, the CPUC is indicating that inaccurate hosting-capacity maps are now a regulatory compliance issue, not just a stakeholder frustration. The resolution holds SDG&E noncompliant on redaction practices, reinforcing that these are enforceable obligations.

For developers, DER providers, and large-load customers, the main takeaway is that Integration Capacity Analysis outputs will become more auditable as the new tracking and reporting requirements take effect (concordance tracking within six months, substation portal updates within three).

The framework creates equal scrutiny for both false positives (ICA shows capacity, engineering finds a constraint) and false negatives (ICA shows a constraint, engineering finds capacity), giving utilities reason to improve methodology accuracy rather than systematically shade results in either direction.

UPDATE: A separate issue that surfaced late in the proceeding warrants watching: the Interstate Renewable Energy Council raised concerns that PG&E inserted a "safety bank" criterion not authorized by Commission orders, which can trigger redaction of ICA Static Grid results (a critical output for interconnection customers).

The resolution does not resolve the issue but orders utilities to present on their reverse-power-flow calculations at the next ICA workshop and file a joint advice letter establishing or modifying their approaches. How that proceeding develops could affect interconnection siting intelligence across all three utilities.

ERRA COMPLIANCE

A decision approves SCE's 2023 ERRA compliance application in full. SCE gets a clean record on procurement compliance, contract administration, least-cost dispatch, and account treatments. The financial result: a $63.195 million rate decrease reflecting net overcollections across seven accounts, plus a $70,811 return tied to four 2023 Public Safety Power Shutoff events.

Cal Advocates argued that a series of contract disputes, invoice errors, and a letter of credit defect spanning three record years established a year-to-year pattern of imprudent contract management by SCE, warranting heightened scrutiny in future ERRA proceedings. The decision rejects that framing entirely: each incident had been (or is now) resolved as prudent, and four contracts over multiple years at a 0.0048% error rate does not constitute a pattern. No disallowances. No enhanced disclosure requirements.

The one process constraint: SCE must file a Tier 2 Advice Letter within 60 days to modify its Affiliate Transfer Fee Memorandum Account tariff and return a $219,000 overcollection through the Base Rate Recovery Balancing Account. The CPUC split the remedy, approving the underlying entries now, but requiring staff and public review before formalizing the forward-looking tariff treatment.

INSTANT ANALYSIS: This is a standard compliance approval. Cal Advocates' attempt to convert ERRA into a procurement enforcement vehicle fails. The decision does include one warning, however: two or more contract errors in a single record period may be enough to establish the pattern Cal Advocates couldn't prove here. That language matters for future proceedings.

ENERGY STORAGE INVESTIGATION

The CPUC launched an investigation to determine whether:

• PG&E’s Elkhorn Energy Storage System has been out of service for nine or more consecutive months; and
• The CPUC should eliminate consideration of the plant’s value or disallow associated expenses from rates under Public Utilities Code §455.5 or other statutory authority.

The 182.5 MW/730 MWh battery system at Moss Landing has been offline since June 2, 2025 following a coolant leak during restart. PG&E reports it has no definitive return date and is planning for the facility to remain offline through the remainder of 2026.

While PG&E maintains that energy storage may not qualify as a “generation or production facility” under §455.5, it provided notice voluntarily, triggering the CPUC’s obligation to open this proceeding.

The order launching this rulemaking also directs PG&E to establish a memorandum account to track its authorized revenue requirement and related revenues, with amounts accruing interest and subject to refund from the date the investigation is issued. The matter may ultimately be addressed in coordination with PG&E’s Test Year 2027 General Rate Case.

INSTANT ANALYSIS: If the Commission finds that §455.5 applies to storage, the statute provides a direct path to disallow value and expenses tied to a prolonged outage. If it does not, the CPUC retains authority under “just and reasonable” standards to examine the same cost-recovery question.

• The memorandum account does not determine outcomes, it preserves the ability to reconcile revenues and apply refunds with interest if the CPUC later finds that costs should not have been collected during the outage period.
• The record points to extended uncertainty. PG&E has no restart timeline and is working with Tesla as the maintenance and warranty provider to address the coolant leak. That combination keeps the focus on outage duration, asset classification, and cost recovery rather than safety findings, which are being handled in separate investigations.

At the end of the day, this is a cost-recovery proceeding anchored in outage duration and statutory interpretation, with potential downstream implications for how long-duration outages at utility-owned storage assets are treated in rates.