Current Period
Sep 16 – Sep 30, 2026
6 items
PG&E Wildfire Mitigation Cost Recovery PD — $1.768B of $2.246B Authorized; $477M (21%) Disallowed as Not Incremental or Reasonable
ALJ Elaine Lau’s proposed decision would authorize PG&E to recover approximately $1,768.4 million of 2020–2022 costs recorded in the Wildfire Mitigation Plan Memorandum Account and Fire Risk Mitigation Memorandum Account. PG&E recorded about $2.495 billion over the three years — $969 million in expenses and $1.527 billion in capital — then removed $250 million in accounting adjustments to request $2.246 billion. The PD finds roughly $477 million of the recorded costs not incremental or not reasonable, a 21% reduction to the request. Earliest Commission vote: November 19, 2026.
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Of the recorded total, the WMPMA holds $864 million in expenses and $1.480 billion in capital; the FRMMA holds $105 million in expenses and $47 million in capital. The accounting adjustments PG&E removed before filing were $246.296 million of expense and $3.402 million of capital, and include $233.6 million in revenue requirement removed to comply with the $1.823 billion disallowance ordered in the 2020 Wildfire OII decision (D.20-05-019).
Intervenor positions were far apart. TURN recommended disallowing $1.375 billion, about 55% of recorded costs, arguing PG&E failed to carry its burden on incrementality and reasonableness; counting the D.20-05-019 disallowance, TURN would have capped recovery at $870.5 million, or 39% of the request. Cal Advocates recommended disallowing $613 million of WMPMA capital and $280 million of WMPMA expenses, plus $5 million of FRMMA capital and $22 million of FRMMA expenses. The Energy Producers and Users Coalition and Indicated Shippers argued that spending pursuant to an approved wildfire mitigation plan does not by itself establish that the spending was prudent or affordable.
The PD adopts neither extreme. Its recurring test is whether a cost was genuinely incremental to the 2020 General Rate Case authorization and separately whether it was reasonably incurred — a cost can clear the first and fail the second. Overhead Patrols illustrate the point: the full $6.072 million recorded in MAT BFA is disallowed as unreasonable even though the PD finds the costs incremental, because PG&E performed 4,023,363 base units against 4,476,868 authorized in the GRC. The Overhead Electric Distribution Asset Inspections category recorded $207.332 million in total, of which TURN sought $184.092 million in disallowances.
PG&E has already been collecting against this request in interim rates: D.24-03-006 authorized 75% of the $688 million revenue requirement, or $516 million, and $428.9 million for Track One costs. The proceeding also covers electric modernization and gas safety work performed primarily in 2022, which this PD does not resolve.
CPUC Opens the AB 825 Regional-Market Rulemaking — Decision Targeted for Q3 2027, Markets No Earlier Than January 2028
The Commission opened R.26-09-009 on September 17 to implement Assembly Bill 825 and determine whether PG&E, SCE and SDG&E may participate in electricity markets governed by an independent regional organization. The statute permits CAISO to operate those markets no earlier than January 1, 2028, subject to statutory conditions, and utility participation requires a CPUC decision finding those requirements satisfied. All three utilities are respondents. The preliminary schedule calls for a decision in the third quarter of 2027.
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The proceeding will examine protections for state authority over procurement, resource adequacy, environmental and reliability policies and utility oversight, along with independent market analysis and governance transparency. A threshold question is whether the Commission’s determination may rely on draft governance documents and tariffs or must await final CAISO resolutions and FERC-approved tariff changes; the rulemaking also asks whether an interim process is needed if CAISO’s transition advances before the Commission completes its review.
Other issues include procedures for directing utilities to withdraw, CAISO’s ability to provide separate market services after withdrawal, and authorization of additional regional-organization products including a potential resource adequacy program. The CPUC will coordinate with the California Energy Commission to prevent the transition from expanding which transactions qualify for RPS content categories, measured against a December 31, 2025 baseline.
The order does not resolve whether the Q3 2027 decision will itself authorize participation or instead establish the process for a later determination. Requiring final governance documents and FERC-approved tariffs would compress the interval before the earliest permitted January 2028 launch. The withdrawal questions bear directly on how readily the Commission can exercise retained authority, since utilities are separately required by statute to participate in CAISO.
PCIA Banked RECs — Pre-2019 Credits Affirmed at Zero; CalCCA’s Departed-Customer Claim Rejected as Untimely
A decision affirms zero-dollar valuation of renewable energy credits generated before January 1, 2019 and banked for later use in PG&E, SCE and SDG&E’s Power Charge Indifference Adjustment calculations. It rejects additional compensation for customers who helped fund those credits but left utility generation service before the credits were used for renewable compliance. The Commission found the credits’ costs and benefits fully allocated under the 2011 methodology adopted in D.11-12-018, which recognized renewable resources’ market value in the year of generation.
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D.19-10-001 shifted REC valuation to the time credits are sold or used, but only for credits generated beginning in 2019. Because customer indifference was already satisfied for the older credits, the decision concludes that another payment would violate cost-shifting prohibitions.
CalCCA sought vintage-specific credits at the current RPS market price benchmark, or allocation of the credits to departed customers’ providers; Cal Advocates and direct-access representatives also supported non-zero valuation. The decision adopts the utilities’ position, rejects four staff alternatives and finds CalCCA’s challenges to the earlier decisions untimely. The final revision limits its separate laches finding to the failure to challenge the 2019 decision.
The decision resolves differing treatment across utilities: PG&E’s 2023–2025 ERRA forecast cases used RPS benchmark valuation, while SCE’s disputed cases used zero-dollar valuation. Uniform zero-dollar treatment applies
through the October updates in the utilities’ 2027 ERRA forecast proceedings, affecting 2026 true-ups and 2027 forecast rates without otherwise reopening earlier outcomes. CalCCA executive director Beth Vaughan called the outcome “deeply disappointing,” saying the association had urged the Commission for six years to give CCA customers their share of the value of banked credits they helped pay for.
The reasoning treats the original allocation as complete even where the customers funding a resource and those benefiting from its eventual use differ, which forecloses a further PCIA credit without requiring the Commission to determine the banked credits’ present compliance value.
Tribal Land Transfer Policy Extended to Surplus Utility Property; 60/30/15/90-Day Negotiation Clock Adopted, R.22-02-002 Closed
A decision expands the CPUC’s Tribal Land Transfer Policy to surplus utility property, giving tribes an opportunity to negotiate for ancestral lands before utilities seek other buyers. It covers property removed from rate base because it is no longer necessary or useful for utility service, but exempts land removed to benefit utility operations, such as mitigation for capital projects. Transactions outside Public Utilities Code Section 851 require no new CPUC approval but must comply with the policy. Telecommunications providers remain excluded.
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For each covered transaction a utility must request the Office of the Tribal Advisor’s list of relevant tribes. Tribes receive 60 days to express interest, with a second notice and another 30 days for nonrespondents. A utility must establish a virtual data room within 15 business days after a tribe expresses interest, beginning a 90-day negotiation period; it may then seek other buyers if no agreement in principle exists and none appears reasonably imminent.
Data rooms must contain available property records and a current appraisal, with a broker’s opinion of value permitted temporarily. Confidential cultural information remains subject to legal disclosure restrictions. Electric and gas utilities must report quarterly on dispositions and tribal engagement; water utilities report annually. Competing tribal claims proceed first through discussions among tribes, then through alternative dispute resolution and, if unresolved, to a Commission decision.
The decision also revises tribal consultation responsibilities, establishes quarterly Tribal Information Forums open to all California Native American tribes, and provides for review of the consultation policy every three years. It closes R.22-02-002 while leaving taxation, jurisdiction and infrastructure delays for further engagement. The Commission acknowledged that the Tribal Advisor position is vacant and said it would coordinate with the governor’s office to fill it — a consideration given that implementation rests heavily on that office.
SGIP Rulemaking R.20-05-012 Closed; SCE Medical-Baseline Waiver Preserves $1.7M in Reserved Incentives
A decision closes the Self-Generation Incentive Program rulemaking while implementation and wind-down of the Residential Solar and Storage Equity program continue through 2028; funding allocation ended in June 2026. The decision also waives demand-response enrollment requirements for certain SCE Medical Baseline Exemption customers whose SGIP projects faced expiration because they receive generation service from another provider and could not satisfy the requirement — protecting approximately $1.7 million in reserved incentives. No party opposed the waiver.
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Medical Baseline Exemption customers must preserve stored energy for medical equipment and are excluded from qualifying demand-response programs, which is why the enrollment condition could not be met. The waiver removes that barrier while preserving the customers’ generation-provider choice and MB-E schedule.
The California Solar & Storage Association opposed closing the proceeding, citing payment delays, project deadlines and the absence of the cost-attestation process from the SGIP Handbook. It warned that administrators could reject baseline-supported incentive claims without an open proceeding to resolve disputes, and sought corrective action regarding LADWP’s administration. The decision finds that earlier rulings addressed baseline and payment issues and that existing program mechanisms can handle remaining concerns.
The proceeding therefore closes with program implementation still underway, and the attestation process is not codified in the Handbook; the decision relies instead on existing rules, working groups and staff coordination to address future disputes.
PD Would Deny SDG&E’s Exit From Regional Energy-Efficiency Administration — Claimed $300M Saving Reduced to About $14M
A proposed decision would deny SDG&E’s request to stop administering regional energy-efficiency programs from 2027 through 2032, finding the request premature and unsupported by the record. SDG&E estimated that ending the portfolio would avoid $300 million in customer collections over six years, or $1.36 per month for an average residential gas and electric customer. The PD finds that calculation omits SDG&E’s own forecast of at least $286 million in foregone Total System Benefits, leaving roughly $14 million in net savings before longer-term energy, grid and equity benefits. Earliest CPUC vote: October 8.
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Under the PD, SDG&E would remain responsible for its regional portfolio and codes-and-standards programs but could eliminate underperforming programs and rebalance spending. Public Purpose Program charges, which fund energy efficiency and other programs, represent about 1.4% of SDG&E bills.
The PD rejects the argument that regional efficiency has become structurally uneconomic. SDG&E’s resource-acquisition segment achieved a 1.19 Total Resource Cost ratio in 2025, or 1.05 excluding statewide programs; six of seven regional programs had ratios at or near 1.0 in 2024, while the Federal Customer Services Program recorded a 0.03 ratio. Reforming or eliminating weak programs could improve performance without ending the portfolio.
The CPUC has legal authority to select administrators other than utilities, but the PD finds SDG&E did not show that its efficiency targets were infeasible, uneconomic or harmful to public health, nor that the San Diego Regional Energy Network could replace its portfolio — SDREN was designed to supplement SDG&E’s programs, and approximately 8% of SDG&E’s electric customers live outside its coverage. The PD also rejects an SDG&E–Cal Advocates settlement that would have ended SDG&E’s administration of regional programs and codes-and-standards activities.
SDG&E prevailed on the legal question that utilities need not administer regional programs indefinitely, but the improving cost-effectiveness results undercut the factual case for withdrawal. The PD leaves a path for a future exit conditioned on a willing replacement, an orderly transition and a plan to preserve customer and grid benefits.
Prior Period
Sep 1 – Sep 15, 2026
16 items
CPUC Opens a Rulemaking to Overhaul the General Rate Case Plan — First Comprehensive Revision Since 2007
A new rulemaking would rewrite the General Rate Case Plan governing California energy utilities. It would update filing requirements not comprehensively revised since 2007, standardize utility evidence and workpapers, implement recent legislation, and revive unresolved proposals from the CPUC’s 2020–2021 GRC and RAMP workshops. The OIR follows the Commission’s goal of reducing electric-service costs by bringing more spending and rate impacts into the GRC for consolidated review, and asks whether thresholds should be set for major cost-recovery or infrastructure requests filed outside a GRC.
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The OIR asks whether utilities should provide more standardized units, unit costs and other metrics for capital, O&M and indirect costs; formal requirements for electronic workpapers with functioning cells and searchable PDFs; consistent bill-impact calculations; more standardized Results of Operations models and depreciation studies; better support for post-test-year forecasts; and information on distributed-energy load growth, locations and costs.
The rulemaking would use the GRC process to show whether utility spending actually matches what ratepayers were asked to fund, what major capital investments will cost over time, and how wildfire spending is reflected in rates — implementing statutory requirements for comparing actual costs and returns with prior forecasts, showing multi-year rate impacts of capital projects, and tying Wildfire Mitigation Plans more directly to GRC revenue requirements. For wildfire costs recorded outside base rates, it asks what utilities should have to prove before recovery, including whether costs were reasonable, incremental and foreseeable.
Attachment A preserves the four-year cadence: RAMP begins three years before the test year; the Phase 1 GRC is filed May 15 two years before the test year; hearings follow that February and March; a final decision is targeted for December 1 before rates take effect January 1. Attachment B brings the 2020–2021 workshop disputes over standardized filings, rebuttable presumptions, attrition ratemaking and Results of Operations modeling back into consideration.
Competing Biomethane PDs — Houck Would Hold RGS Above-Market Costs With Core Customers; Reynolds’ Alternate Charges Noncore Immediately
Competing proposed decisions in the biomethane cost-allocation rulemaking adopt the same method for calculating Renewable Gas Standard above-market costs but split on who pays them first. Commissioner Houck’s PD allocates costs to all core customers, including those served by Core Transport Agents, while deferring charges for noncore customers. President Reynolds’ alternate PD charges all core and noncore customers immediately. Approximately 1,020 noncore customers consume about 60% of utility-delivered gas, so an equal-cents-per-therm allocation could shift most above-market costs to industrial facilities and electric generators — even though the program’s eventual costs remain unknown.
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Both proposals define above-market costs as all authorized program costs exceeding the monthly average citygate price of natural gas, less avoided greenhouse-gas compliance costs and other quantifiable benefits. Utilities would recover the resulting amount through transportation rates on an equal-cents-per-therm basis. CARE discounts are preserved; no other immediate exemptions are created. Both PDs require workshops on possible exemptions for emissions-intensive, trade-exposed industries, followed by a joint utility application within 18 months of the first workshop.
Both also carry apparent drafting errors that parties can raise before a vote. Reynolds’ APD orders immediate noncore allocation while directing the later application to ask whether it should be implemented. Houck’s PD substitutes “core” for “non-core” in its discussion and in one conclusion of law.
SoCalGas TIMP PD — $81.3M of a $173.8M Request Authorized; $92.5M Disallowed Over an Unjustified Accelerated Schedule
A proposed decision would authorize SoCalGas to recover $81.3048 million of its $173.8 million request for Transmission Integrity Management Program costs incurred 2019–2023, disallowing $92.4952 million. The PD concludes that expanded pipeline-safety requirements justified some additional work but that SoCalGas failed to justify its accelerated schedule — spreading the work across the longer federal compliance period and forecasting it in a GRC would have allowed greater scrutiny and reduced rate shock. On that basis it disallows $54.2032 million, 40% of the amount remaining after specific adjustments.
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The PD separately disallows $34.328 million in straight-time labor, $3.271 million in related leave costs and $693,000 associated with an inadequately documented vendor. It states that $40.72 million in Line 235 costs is recoverable subject to refund pending a separate advice letter. The approved balance would be allocated under the 2024 Cost Allocation Proceeding decision (D.24-07-009) and recovered over 12 months.
The PD treats the timing of mandatory safety work as a question of prudence: because federal rules gave SoCalGas more time to complete some of the work, the utility had to justify both accelerating it and recovering the costs outside the GRC. Even required work may be found unreasonable if the utility cannot support its timing, cost or documentation.
Three internal problems are available for parties to raise. First, the PD references the $173.8 million request when describing the 40% reduction, although the resulting $54.2032 million is 40% of the $135.508 million remaining after the specific disallowances. Second, it does not explain whether the full $40.72 million authorized for Line 235 survives that aggregate reduction. Third, the Line 235 refund condition appears in the findings of fact and conclusions of law but not in an ordering paragraph, leaving the operative order silent on the condition.
SoCalGas Customer Information System PD — $24.9M in Additional O&M Denied; SBUA Settlement Rejected
A proposed decision would deny SoCalGas’s request for up to $24.9 million in additional O&M funding for its Customer Information System Replacement Program. The CPUC authorized $46.9 million in the 2024 GRC and allowed the utility to seek more if projected costs exceeded that amount; SoCalGas now forecasts total O&M of roughly $71 million. The PD finds the utility has not shown the existing authorization will be insufficient — it spent $8.463 million in 2024 against a $16.87 million forecast, and $5.821 million through September 2025 against an $11.183 million full-year projection — and provided no finalized contracts supporting the higher forecast.
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The PD concludes that denial will not delay the system’s planned third-quarter 2026 launch or its stabilization through 2027. It rejects a settlement between SoCalGas and Small Business Utility Advocates that would have reduced the additional funding to $21 million, established a two-way balancing account and provided up to $150,000 for small-business outreach — the settlement did not address contrary evidence from Cal Advocates and omitted the required comparison exhibit showing its ratepayer effects.
The PD separately grants Cal Advocates’ late request to admit a SoCalGas data response into evidence but admonishes parties against relying on new exhibits in reply briefs. Any further funding request would be considered in SoCalGas’s next GRC based on actual spending.
The disposition turns on burden: SoCalGas was permitted to seek additional funding, but still had to prove the original authorization would be insufficient. Recorded spending stayed below earlier projections and no binding commitments supported the anticipated increase. The rejection of the settlement also establishes that negotiating a smaller request does not by itself show the remaining amount is reasonable.
Direct Access Cap — Reynolds PD Would Deny the Petition to Reopen, Resting on Timeliness Rather Than the Merits
President Reynolds issued a proposed decision rejecting an effort by retail-energy suppliers and large customers to eliminate California’s cap on Direct Access. The petitioners — the Alliance for Retail Energy Markets, the California Coalition of Large Energy Users, the Direct Access Customer Coalition, the Regents of the University of California, Shell Energy North America and the Western Power Trading Forum — asked the CPUC to reverse its 2021 recommendation against expanding the program. The PD does not decide whether changed conditions justify expansion: it finds the petition lacks declarations or record citations for several factual claims and was filed nearly five years after the 2021 decision.
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The petitioners argued that the conditions underlying the 2021 recommendation have changed, citing stronger resource-adequacy and renewable-procurement performance by electric service providers, a shift from RA scarcity in 2020 to a current surplus, and rapid load growth from data centers and electric vehicles. They also argued that the CPUC’s 2026 IRP decision (D.26-02-057) requires ESPs to procure a share of 6 GW of new renewable capacity for forecast load growth while the Direct Access cap prevents them from serving much of that new load.
The PD concludes that the effects of the cap and of load-based procurement obligations were known or reasonably foreseeable within one year of the 2021 decision, and that reversing it and resolving previously undecided cost-shift questions would require a fuller evidentiary record.
Note: four of the petitioners separately filed a same-day application for rehearing of the IRP decision challenging its allocation of procurement obligations to ESPs. This PD addresses only the petition to modify the 2021 Direct Access decision and does not resolve that application.
If adopted, the PD would close the old proceeding, leaving the underlying issue intact — ESPs may receive procurement obligations tied to statewide load growth without being allowed to compete for much of that load. Further expansion would then likely require new legislation or a new CPUC proceeding.
ALJ Orders a Joint IOU Proposal Within 45 Days to Implement AB 2109’s Surcharge Exemption for Industrial Heat Recovery
A new ALJ ruling directs PG&E, SCE and SDG&E to submit a joint proposal within 45 days for implementing Assembly Bill 2109’s exemption from certain non-bypassable charges for electricity savings produced by industrial process heat-recovery systems. The proposal must identify which charges should and should not be exempted, establish technology and compliance requirements, and recommend a participation cap and its allocation among the utilities.
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The joint proposal must also estimate rate and bill impacts on non-participating customers by customer class and consider limits or other measures to reduce cost shifts. Parties may comment on the proposal, on additional customer protections and on alternative approaches.
AB 2109 created the surcharge exemption but left the CPUC to define its financial and administrative reach. How the Commission defines the participation cap, the eligible charges and the cost-shift protections will determine how much industrial customers can save by reducing grid consumption through recovered heat. The joint proposal will also produce the first quantified estimate of the resulting effects on other customer classes.
2027-2028 TPP Portfolio Ruling — Interim GHG Targets Raised to 38/30 MMT, Offshore Wind Dropped From the Base Case, 4,400 MW West LA Storage in Play
The CPUC is seeking comment on a proposed resource portfolio for CAISO’s 2027-2028 Transmission Planning Process that would raise California’s interim greenhouse-gas targets and stop forcing offshore wind into the base case. Staff recommends 38 MMT by 2030 and 30 MMT by 2035 instead of 30 and 25, while still reaching 8 MMT by 2045. Staff says the lower interim targets would require solar additions of about 8 GW per year through 2030 and cost at least $1 billion more by 2030 and $2 billion more by 2035 — even though the added resources are not needed to meet the CPUC’s reliability standard.
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The recommended base case would no longer force offshore wind into the portfolio, reversing the approach used in the previous three TPP cycles. Staff cites federal policy and permitting uncertainty, terminated California leases and reduced offshore-wind interest in recent LSE plans. RESOLVE economically selects no offshore wind under the proposed assumptions, relying instead on solar, battery storage and increasing amounts of conventional and enhanced geothermal. The base case retains about half of the previously identified long-lead-time procurement need, excluding offshore wind.
For a sensitivity study, staff recommends limiting additional out-of-state resources to those deliverable over transmission already operating or under contract; RESOLVE then selects 54.8 GW of new solar and 20.1 GW of new eight-hour storage by 2035.
The ruling separately asks whether storage should be procured in the West Los Angeles Basin after CAISO cancelled the Serrano-Del Amo-Mesa 500-kV project. CAISO says at least 4,400 MW / 12,428 MWh should come online across specified West LA substations by 2032, and has recommended a CPUC procurement order for 2,900 MW / 2,336 MWh by Q2 2032. The ruling notes that amount would meet the identified need only if projects already in the interconnection queue are completed, and that the batteries would operate as market resources without special compensation for performing a transmission function. A 2022 decision (D.22-02-004) authorized similar storage procurement for the Kern-Lamont line and Mesa system, but PG&E found no viable offers able to meet the required online date. The ruling also raises whether SCE, as Local Central Procurement Entity for its area, could handle the West LA procurement.
SB 1221 Phase 2 Staff Proposal — 67% Owner Consent, Up to 25% of Net Savings to Shareholders, Priority Zones Expanded 151 → 304 Tracts
The CPUC is seeking comment on an Energy Division proposal for the next phase of Senate Bill 1221’s neighborhood decarbonization program — when pilot projects are considered “established,” how utilities could earn shareholder incentives, and when gas service can be retired within approved project areas. Staff proposes treating a project as established when the CPUC approves it, regardless of when property-owner consent is obtained. Utilities could earn up to 25% of verified net savings from qualifying projects completed in a given year. Projects would require binding consent from owners of at least 67% of properties before implementation.
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Performance would be based on pipeline mileage retired, customer conversions, the share of converted customers in designated communities, and project performance against budget. Staff seeks comment on three alternative customer-conversion metrics.
The CPUC would determine whether proposed zero-emission alternatives provide affordable, adequate, efficient and just-and-reasonable substitute service, including a no-cost option. After completion the utility would file a Tier 3 advice letter; approval would relieve it of the obligation to serve the project area, after which remaining gas service could be ended even for owners who declined conversion. Staff also asks whether substitute service should cover only common gas end uses or every existing onsite gas use.
The proposal would expand the current 151 priority neighborhood decarbonization zones to 304 full census tracts plus nine partial tribal tracts across 26 counties. SB 1221 limits each utility’s pilots to no more than 1% of its customers. Recurring project reporting and annual updates to SB 1221 gas-system maps would begin in 2027.
Once a project receives CPUC approval and reaches the 67% consent threshold, the program can move toward full retirement of gas service within that area. The proposed incentive would also give utilities a financial reason to pursue locations where electrification costs less than replacing gas infrastructure; allowing shareholders to retain up to 25% of verified net savings could make avoided pipeline replacement more attractive. The 1% customer cap keeps the program limited in scale for now.
Draft Res. E-5472 — Meter Socket Adapter Filings Approved; Future Truck-Roll Fee Increases Pushed to Tier 3 Review
Draft Resolution E-5472 approves SCE’s meter socket adapter filing and SDG&E’s equivalent filing with modifications, while imposing new fee-transparency requirements on all three large electric IOUs. SDG&E must disclose its MSA “truck roll” fee on its public webpage. PG&E, SCE and SDG&E would have 60 days to revise their tariffs through Tier 2 advice letters to state the current fee and to require any future increase to proceed through a Tier 3 advice letter supported by calculations, cost data and methodology. PG&E currently charges $275 and SCE $279.22; SDG&E has not publicly listed its amount.
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The draft resolution reiterates that the evaluation framework is technology-agnostic and extends beyond meter socket adapters to other customer-owned technologies that interface with utility equipment. MSAs can enable EV charging, battery storage and other electrification equipment without requiring panel replacement or service-line upsizing.
By requiring Tier 3 review and detailed cost support for future truck-roll fee changes, E-5472 would make those charges more transparent and less subject to informal utility adjustment.
Res. E-5475 Adopted — Ava’s New Sonrisa Project Counts as Incremental, Not Baseline; Baseline-Removal Waiver Expanded to Tier 2
The Commission adopted Resolution E-5475 on September 17. The resolution confirms that Ava Community Energy’s newly contracted Sonrisa project is distinct from a project of the same name included in the resource baseline established under the 2021 Mid-Term Reliability Decision (D.21-06-035). The new project is a 200 MW solar facility paired with 184 MW / 736 MWh of storage. The earlier project never advanced because of an infeasible interconnection configuration. On Ava’s unprotested showing, the draft resolution finds the new project differs in size, commercial operation date, design, technology, land footprint, interconnection configuration and permitting status — so it counts as incremental procurement rather than an existing baseline resource.
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Ava — formerly East Bay Community Energy — requested the determination in Advice Letter 70-E, filed June 1. The resolution also allows load-serving entities to seek removal of baseline projects that were not developed, are no longer under contract and are no longer advancing. Such requests would be submitted through a Tier 2 advice letter, expanding a waiver process that D.23-02-040 previously limited to cases in which one LSE terminated a contract and another contracted with the same resource. Ava’s advice letter was not protested, and the resolution identifies no associated costs. It does not quantify how much of Ava’s procurement obligation the project will satisfy.
GO 95 PD Replaces Working Stress Design With Load and Resistance Factor Design for Overhead Facilities
A proposed decision replaces the Working Stress Design methodology in General Order 95 with Load and Resistance Factor Design for overhead electric and communications facilities. The initial load and strength factors would remain algebraically equivalent to existing requirements, but the proposal would allow factored loads to be used in certain structural calculations where doing so produces larger load effects. The revisions would take effect July 1, 2027. The Commission held the item at its September 17 meeting; it is now scheduled for consideration on October 8.
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The proposal rejects utility-backed language expressly allowing older facilities to demonstrate compliance under the former methodology. Existing facilities would not automatically require redesign, but calculations required by GO 95 would use Load and Resistance Factor Design — preserving the Commission’s ability to apply future load-and-strength-factor changes to existing facilities.
Commission staff would also hold a workshop within 24 months to consider further GO 95 revisions. A statistical safety study is deferred because the initial change maintains algebraic equivalence.
Draft Res. E-5476 Adopts the 2026 Avoided Cost Calculator — Total Avoided Costs Rise in Every Hour, Driven by GHG Value
Draft Resolution E-5476 would adopt the 2026 Avoided Cost Calculator for evaluating demand-side distributed energy resources, implementing changes approved September 3 in D.26-09-007: a single electric-sector greenhouse-gas value for electric and gas resources, removal of GHG rebalancing, simplified treatment of hybrid solar-plus-storage resources and use of loss-of-load hours for allocating capacity value. The 2026 calculator produces higher total avoided costs in every hour than the 2024 version. Earliest CPUC vote: October 8.
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The draft resolution also uses energy prices rather than temperature to identify high-value days, distinguishes weekday and weekend reliability risk, uses the
Integrated Energy Policy Report forecast in peak capacity allocation factor calculations for transmission avoided costs, and applies the “Discounted Total Investment Method” across electric utilities.
Individual components move differently even as the total rises. Increased renewable penetration lowers avoided energy value; generation-capacity value falls in the near term, rises in later years and is distributed across more overnight hours to reflect storage dispatch. The largest increase comes from the GHG component, which rises substantially because the model incorporates expiring federal renewable-energy tax credits and new tariffs on imported solar and storage components.
The net effect should make DER programs appear more cost-effective where higher GHG benefits outweigh lower energy and near-term capacity values, with measures producing sustained emissions reductions benefiting most and resources relying heavily on near-term capacity value benefiting least. Federal policy enters the results primarily through the GHG component: reduced federal support and tariffs increase the modeled cost of utility-scale solar and storage used to reduce emissions, which increases the calculated value of demand-side resources that avoid those costs.
Draft Res. E-5483 — PG&E’s $1.224B Diablo Canyon True-Up Clears the 115% Threshold; TURN’s Category-by-Category Test Denied
Draft Resolution E-5483 would authorize PG&E’s true-up of Diablo Canyon extended-operations costs and market revenues for September 1, 2023 through December 31, 2025. PG&E recorded approximately $1.224 billion in costs, below 115% of the applicable forecast under both the original and updated Resource Adequacy Market Price Benchmark calculations, so the draft finds that Public Utilities Code Section 712.8 requires no further reasonableness review. It would also approve allocation of Diablo Canyon’s greenhouse-gas-free attributes to 31 eligible load-serving entities for 2025. Costs are recovered from PG&E, SCE and SDG&E customers through non-bypassable charges already in rates; the resolution would authorize no additional rate increase. Earliest CPUC vote: October 8.
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The draft resolution would deny TURN’s protest seeking to apply the 115% threshold separately to each cost category. TURN argued the aggregate calculation obscures approximately 10% overruns in operations and maintenance and in plant equipment and improvement costs, while a $132.2 million reduction in Resource Adequacy substitution capacity costs supplies much of the offset. The draft concludes that the statute calls for comparing total actual and forecast costs, that the same approach is used for other balancing accounts, and that neither disputed category exceeded 115% of its own forecast.
TURN’s proposal would not change the outcome for this record period, since PG&E remains below the statutory trigger under either calculation. The forward-looking effect is the aggregate reading itself: savings or methodology changes in one category can offset overruns elsewhere, including in categories more directly within PG&E’s control. TURN’s examples show an individual category exceeding its forecast by 30% to 65% without triggering review, but the draft reads Section 712.8(h)(1) as providing no category-specific test.
The draft appears internally inconsistent about the updated forecast: its discussion identifies an updated Market Price Benchmark forecast of $1.193 billion, while Finding 4 associates the $1.325 billion original forecast with both calculations. The stated conclusion remains mathematically correct under either figure.
2027 Wildfire Fund Charge Proposed at $5.42/MWh — Down 8.3%, but a True-Up Rather Than a Revenue-Requirement Cut
A ruling seeks comment on the Department of Water Resources’ proposal to set the 2027 Wildfire Fund Non-Bypassable Charge at $5.42/MWh ($0.00542/kWh), effective January 1, 2027 on non-exempt load in the PG&E, SCE and SDG&E service territories. That is $0.49/MWh, or 8.3%, below the 2026 charge of $5.91/MWh. DWR’s 90-day notice projects collections of $854.6 million during 2027, $47.8 million less than the fixed $902.4 million annual revenue requirement, with the difference offsetting the cumulative overcollection projected through the end of 2026. Comments were due September 21, replies September 28.
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DWR calculated the rate using actual collections through June 2026, projected collections for the remainder of the year and the utilities’ 2027 load forecasts. The forecast includes 158.7 million MWh of non-exempt load — 67.9 million MWh bundled and 90.8 million MWh of direct access, community choice aggregation and other departing load — and accounts for uncollectible amounts and the roughly 30-day lag between customer billing and remittance. An attached memo projects $849.1 million in transfers to the Wildfire Fund and $6.4 million in administrative and operating costs during 2027, with no bond debt-service expense.
The reduction does not lower the Fund’s $902.4 million annual revenue requirement; it returns the cumulative overcollection expected through 2026. At 1,000 kWh of monthly usage the charge falls from $5.91 to $5.42. The Commission has limited discretion over the annual revenue requirement: the Wildfire Rate Agreement requires it to maintain collections sufficient to meet the requirement and has the force of an irrevocable financing order. The comment process is therefore more likely to examine DWR’s load forecasts, collection assumptions and calculation than the amount dedicated to the program.
DAC-SASH PD — Accrued Interest Redirected to Administration and Outreach; GRID’s $1,000/kWh Battery Incentive Rejected
A proposed decision would modify the Disadvantaged Communities–Single-Family Solar Homes program, which has a $10 million annual budget and provides no-cost rooftop solar to income-qualified homeowners in disadvantaged communities and California Indian Country. As of December 2024 it had supported 2,886 interconnected systems totalling more than 11.5 MW with approximately $53.2 million in incentives. The PD would let PG&E, SCE and SDG&E use accrued interest in their DAC-SASH balancing accounts for utility administration and marketing, education and outreach through 2030 — $3.588 million accrued against $2.349 million in forecast remaining costs, leaving about $1.239 million. Earliest CPUC vote: October 8.
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Public Purpose Program charges became the program’s sole funding source on
July 1, 2026, and the program is scheduled to sunset
December 31, 2030. Recovery of the accrued interest would be limited to the forecasts absent further authorization and would occur without a rate of return through annual Energy Resource Recovery Account applications. SDG&E would be prohibited from transferring more than its authorized
10.3% share of annual program funding into its balancing account.
GRID Alternatives would be required to report external funding used to complete individual projects, tracking DAC-SASH and external costs, total project cost and the external-funding percentage. GRID could use
$50,000 of accrued interest to develop the reporting system and must file an implementation plan through a Tier 2 advice letter, with the new information appearing in its first semiannual report for 2027.
The PD adopts the revised Version 7 handbook, which retains the
$3/W incentive and the Expected Performance Based Buydown Calculator, requires GRID to track enrollment in related assistance programs, and prohibits combined incentives from exceeding project costs. It makes qualifying meter socket adapters eligible while removing job-training, trainee-hiring and energy-efficiency-education requirements, and rejects GRID’s proposed
$1,000/kWh battery incentive.
Rejecting storage and eliminating workforce requirements preserves more of the fixed budget for installations, favouring household count over resilience or employment benefits. The external-funding requirement addresses a gap in the Commission’s information: GRID’s ability to supplement DAC-SASH with outside funds helped it win the administrator role, but the CPUC has lacked data on how much external support individual projects require. GRID would not have to identify funding sources or allocate external support among cost categories.
Houck Ruling Extends High-GWP Heat-Pump Deadlines and Eliminates the Installation Cutoff for Other HVAC Systems
Assigned Commissioner Darcie Houck’s September 15 ruling extends several eligibility deadlines and eliminates another for heat-pump equipment using refrigerants with a global warming potential above 750 under the BUILD Program and the TECH Initiative. Variable refrigerant flow HVAC systems manufactured before January 1, 2026 and installed before January 1, 2027 remain eligible — both deadlines extended by one year to align with California Air Resources Board and U.S. EPA requirements.
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For self-contained heat pump products — packaged terminal, room and rooftop systems — the ruling retains the requirement that equipment be manufactured before January 1, 2025 but extends the installation deadline from January 1, 2026 to January 1, 2028. For other heat pump HVAC systems it retains the January 1, 2025 manufacturing cutoff but eliminates the installation deadline entirely. It also extends eligibility to high-GWP heat pump water heaters and dryers installed before January 1, 2028.
The refrigerant restriction originated in a 2020 decision implementing Senate Bill 1477 and was extended through assigned commissioner rulings issued in 2022 and 2025. The new ruling separates HVAC equipment into the categories used by CARB and the EPA, and notes that federal requirements supersede the CPUC’s rules by limiting new VRF and self-contained systems to refrigerants below 700 GWP after the applicable federal deadlines.
The most consequential change is the elimination of the installation deadline for high-GWP heat pump HVAC systems outside the VRF and self-contained categories: equipment in that category manufactured before 2025 remains eligible for BUILD and TECH incentives without a separate installation cutoff. The ruling otherwise leaves the transition away from high-GWP refrigerants intact while giving manufacturers and installers more time to use qualifying equipment; heat pump water heaters and dryers receive another year because of limited market development.
Earlier Period
Aug 16 – Aug 31, 2026
14 items
RA Track 2 Scoping Memo — UCAP Implementation, 2028–2030 LCRs and the Planning Reserve Margin, Concluding June 2027
Assigned Commissioner Reynolds issued an amended scoping memo setting the scope and schedule for Track 2 of the Resource Adequacy proceeding, expected to conclude by the end of June 2027. Track 1 was resolved last month in D.26-07-008, which adopted an Unforced Capacity (UCAP) framework beginning with the 2028 RA compliance year. Track 2 focuses heavily on implementing that framework, along with setting 2028–2030 Local Capacity Requirements, the 2028 Flexible Capacity Requirements and the Planning Reserve Margin for 2028 and 2029.
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A substantial portion of Track 2 concerns unresolved UCAP implementation details: how UCAP should be implemented for energy storage under the Slice-of-Day framework; the appropriate basis for RA must-offer obligations once UCAP replaces installed capacity as the qualifying-capacity methodology; development of Equivalent Forced Outage Rate during Demand values for the energy component of storage; a UCAP methodology for hybrid storage resources; treatment of foldback limitations during the fifth RA Measurement Hour; how UCAP values should interact with flexible RA; and application of the four-hour discharge requirement for storage to qualify for RA capacity.
Track 2 will also consider a method for accounting for open-loop pumped-storage hydropower that recognizes both its hydro and storage characteristics; whether energy-only resources can contribute to storage charging-sufficiency requirements following CAISO transmission-planning studies; and improved accreditation for solar, wind and other non-dispatchable resources, including a methodology intended to address over-counting of solar in summer and under-counting in winter. The Commission will revisit the RA penalty structure, specifically how penalty points should apply to charging deficiencies, and may address coordination between RA and Integrated Resource Planning.
Schedule: the 2028 LOLE and PRM study is expected in October 2026, with final LOLE studies and PRM proposals due October 13, opening comments November 12 and replies December 3. Most other Track 2 proposals are due January 15, 2027. CAISO’s local- and flexible-capacity studies arrive in spring 2027 ahead of a June decision.
Sempra 2028 GRC Scoping Memo — Earnings Sharing Begins Only Beyond 200 Basis Points; SDG&E Keeps 2024–2027 Wildfire Costs Out
Commissioner Douglas issued a scoping memo for the Sempra utilities’ 2028 General Rate Cases, whose possible consolidation with other proceedings is pending. SoCalGas requests a $5.1 billion revenue requirement, up $485 million (10.5%) from 2027, raising the average non-CARE residential gas bill by $5.67/month (7.7%). SDG&E seeks a combined $3.8 billion ($2.9B electric, $900M gas), up $280 million (8.1%) — about $22.48/month (8.6%) for a typical combined customer. Both also seek additional increases for 2029 through 2031.
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The CPUC will examine whether the proposed 2028 costs and recovery mechanisms are just and reasonable, along with post-test-year adjustment mechanisms, balancing and memorandum accounts, safety and risk-management proposals, workforce impacts, and consistency with California’s climate, decarbonization and future natural-gas-demand outlook.
Both utilities propose an earnings-sharing mechanism for 2029–2031: shareholders would retain all gains or losses within 200 basis points of the authorized rate of return; amounts between 201 and 250 basis points would be shared equally with ratepayers; and amounts beyond 250 basis points would flow entirely to ratepayers, with a reciprocal structure on the downside.
The scope incorporates the Commission’s affordability framework, grid-modernization guidance and requirements linking RAMP work to the GRC. SDG&E is not seeking reasonableness review or recovery in this GRC of incremental wildfire-mitigation costs incurred from 2024 through 2027, saying it will seek those costs in another venue; the CPUC will nevertheless consider what future wildfire costs may qualify as “unforeseen” or “incremental” for memorandum-account treatment under Senate Bill 254.
Schedule: intervenor testimony February 15, rebuttal March 31, proposed decision targeted December 1, 2027.
Three AMI Scoping Memos Raise the Evidentiary Bar — SCE’s Application Called Incomplete; SoCalGas Must Explain Retiring the ~86% Still Working
The CPUC is subjecting major smart-meter replacement proposals from SDG&E, SCE and SoCalGas to parallel scrutiny, with new scoping memos focused on whether the utilities have adequately justified replacing first-generation metering systems, demonstrated customer benefits, and considered less costly alternatives. SDG&E seeks about $825 million in Smart Meter 2.0 spending through 2031; SoCalGas seeks roughly $3.76 billion for a systemwide replacement covering about six million customers. For SCE, the Commission finds the record does not adequately explain the four AMI 2.0 configurations considered or why its preferred “Value Upgrade” was optimal, calls the application incomplete, and requires supplemental testimony by September 11.
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For SDG&E, the CPUC will examine whether the project is necessary and least-cost, whether meter-failure forecasts support the proposed replacement schedule, whether repair or life-extension alternatives could reduce costs, and whether lessons from the original AMI deployment have been incorporated. The scope also includes vendor warranties and performance guarantees, phased deployment, alternative financing or ownership structures, cybersecurity, and allocation of costs between gas and electric customers.
For SCE, supplemental testimony must detail the methodology used to compare its baseline, limited, value and advanced options; the costs and benefits of each; risks that projected benefits will not materialize; and detailed hardware, software and subscription costs.
For SoCalGas, the scoping memo puts the necessity of mass replacement, the reasonableness of its cost forecasts and potential stranded investment at issue, and requires supplemental testimony by October 5. SoCalGas must substantiate projections that significant meter-module battery failures will begin around 2030 and explain why systemwide replacement is warranted. One Commission question notes that 2013-vintage modules are projected to have only a 14.18% failure rate in year 20 and asks how SoCalGas would account for removing the approximately 86% projected still to be working. The proceeding will also consider how stranded costs should be allocated between shareholders and ratepayers.
SCE and SoCalGas are not facing wholesale re-litigation of their original AMI deployments, though past performance may inform the new proposals. SDG&E’s review goes further, expressly requiring a retrospective accounting of whether AMI 1.0 delivered its promised benefits.
SAP Migration Scoping Memo — $348M for Phases 1B and 2; the Memorandum Account Will Be Decided Ahead of the Rest
Commissioner Baker issued a scoping memo and ruling for review of SoCalGas/SDG&E’s proposed $348 million revenue requirement for phases 1B and 2 of their SAP Migration Program. The utilities say the work is needed because SAP will discontinue maintenance for several applications used in their enterprise platform at the end of 2027, requiring migration to supported systems before they become obsolete. Notably, the Commission will decide the request to establish a SAP Migration Memorandum Account separately and ahead of the bulk of the case.
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The Commission will examine whether the program’s estimated costs, benefits and requested revenue requirement are reasonable and adequately supported, as well as the proposed memorandum and balancing accounts. Specific questions include whether a two-way balancing account or another ratemaking mechanism should be used; how over- and under-collections should be handled; whether memorandum-account costs should ultimately be transferred to the balancing account; and whether the proposed system average percent change (SAPC) and equal percentage of authorized margin (EPAM) allocation methodologies are appropriate, including whether some EPAM-allocated revenue should be recovered through fixed rather than volumetric charges.
The key ratemaking issue is how much financial risk the CPUC will allow the utilities to shift to customers while the migration is underway. The choice of balancing-account treatment will determine whether forecast errors and cost overruns remain primarily with the utilities or are trued up through rates, and the allocation methodology will determine which customers ultimately bear the approved costs. The separate, expedited decision on the memorandum account is therefore significant: if authorized, it could allow the utilities to begin recording eligible migration costs before the Commission decides how much of the broader $348 million request is reasonable and recoverable.
Schedule: intervenor testimony November 20, concurrent rebuttal December 20.
Draft Res. O-0101 — Torrance Basin Pipeline Granted a 10% Increase to $0.5122/bbl, Against a Claimed 178.1% Entitlement
Draft Resolution O-0101 approves a 10% rate increase for Torrance Basin Pipeline Company’s M-131 crude oil pipeline, raising its tariff to $0.5122 per barrel for shipments from the Kinder Morgan Carson Terminal to Torrance Refining Company and the Valero Asphalt Plant. The increase would raise annual pipeline revenue — and shipper costs — by about $101,966. The draft resolution finds the increase just and reasonable and deems it effective as of December 1, 2025.
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The filing shows that even after the increase, Torrance Basin’s $2.84 million cost of service would exceed expected revenue of $1.12 million by about $1.71 million. The company says those costs could support a 178.1% increase but requested only 10%. The larger shortfall compared with its previous filing is attributed to higher outside-services expenses, which rose by $215,892.
PCIA Reform — PD Would Value Pre-2019 Banked RECs at Zero, Rejecting CalCCA’s Bid for an Additional Departing-Load Credit
A proposed decision in the PCIA/ERRA reform docket would require PG&E, SCE, and SDG&E to value renewable energy credits generated before 2019 and banked for later use at $0 in the PCIA calculation, finding their value was already allocated to departing load under the prior methodology. Comments are due September 2; earliest Commission vote September 17, 2026.
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ALJ Eileen Odell concludes that the newer valuation method — valuing RECs when sold or used for RPS compliance — applies only to RECs generated on or after January 1, 2019; bundled customers already credited departing load for the market value of the underlying renewable resources in the generation years under the then-effective PCIA methodology, so a further credit would itself violate the customer-indifference mandate. The PD also treats CalCCA’s claim as barred by laches: CalCCA acquiesced in the prospective-only reach of the post-2018 rules, and other stakeholders relied on the finality of the earlier decisions. If adopted, the zero-dollar treatment takes effect immediately and flows into the utilities’ October updates for 2027 ERRA forecasts, affecting 2026 true-ups and 2027 rates.
PCIA Reform — Second Amended Scoping Memo Opens Tracks 3A/3B/4, Putting the PCIA’s Structure Itself on the Table
Assigned Commissioner Baker’s second amended scoping memo splits Track 3 into Track 3A (refinements within the existing PCIA: RPS and Energy Price Index benchmarks, GHG-free allocation, re-vintaging rules) and Track 3B (whether alternatives such as securitization, mandatory resource allocation, cost-allocation mechanisms, or rate-stabilization funds should replace it), and defines a Track 4 on further benchmark, Slice-of-Day/ERRA, and volatility reforms. Load-serving entities must meet and confer on disputed access to utility portfolio data within 60 days, with a joint report due within 75 days.
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The memo acknowledges the PCIA already satisfies the statutory indifference standard between bundled and departing customers, then asks whether the same result could be achieved through a less cumbersome design — including market mechanisms to recover and transact the value of new “legacy assets” created through ongoing procurement. Stated goals include reducing year-to-year PCIA volatility, improving benchmark accuracy, assigning costs more accurately by resource vintage, and increasing portfolio-cost transparency within confidentiality limits. The ordered meet-and-confer addresses CCA requests for more utility portfolio data, which the utilities have resisted on relevance and confidentiality grounds.
PG&E Must Break Out How Much of Its Data-Center Forecast Rests on Signed Agreements — Detail Due August 31
A CPUC ruling granted Cal Advocates’ motion to compel PG&E to disclose how much of the data-center load in its 2027 ERRA forecast comes from projects with signed service agreements, versus active applications, versus inquiries. The ruling rejects PG&E’s confidentiality and relevance objections, holding that the Commission may need to look beneath an aggregate forecast to test whether its assumptions are realistic — notable because PG&E itself says data centers are the main driver of its industrial-load growth.
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Cal Advocates argued it needs the assumptions beneath the forecast to determine whether emerging data-center load could have an outsized effect on ratepayers; PG&E countered that the aggregate industrial forecast suffices. The ruling sides with Cal Advocates, noting its broad statutory authority to obtain confidential material and that PG&E should have used the Commission’s existing confidentiality protections rather than withholding. PG&E must provide fully responsive information by August 31 and, within two business days, the draft fall-update data-center forecast it had offered during the discovery dispute. The signed-agreement / application / inquiry breakdown lets parties measure how much projected growth is committed versus speculative before it starts setting rates.
Resource Adequacy — Dueling 2028 LOLE Studies Find CAISO Long on Capacity; ED Headroom of ~6,150 MW vs. SCE’s 16.4% UCAP PRM
ALJ Chiv’s August 17 ruling attached Energy Division’s draft 2028 loss-of-load-expectation study: the projected CAISO portfolio produces no loss-of-load events under base assumptions and could absorb about 6,150 MW of added demand while holding near the one-in-ten-years standard. SCE’s independent PLEXOS study calculated a 16.4% UCAP-based September Planning Reserve Margin. A final ED study and PRM recommendation are due in October, after a September workshop.
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The ED baseline carries roughly 18,300 MW more nameplate than the 2026-study baseline, led by storage and solar. Adding 6,150 MW of flat demand monthly yielded a 0.113 annual LOLE and an unadjusted 21.9% September PRM (HE 20); applying the UCAP methodology adopted in D.26-07-008 (forced-outage and ambient-temperature derates) cut results to about 20.5% (Jul–Oct) and 17% otherwise, and the system stays above standard even with imports zeroed out (0.028 LOLE). SCE used ED’s published assumptions where practicable but ran PLEXOS rather than SERVM, removing 20,935 MW of nameplate (about 19% of non-hydro resources, imports cut ~19%, DR held to 1,700 MW) to produce a 0.085 LOLE within standard. Both studies agree the 2028 portfolio holds more capacity than needed; the open question is how much can come out. ED’s pro-rata capacity-reduction scenario — the design closest to SCE’s — remains unfinished, with the nearest published staff comparator (17.2% September UCAP, flat-load calibration) just 0.8 points above SCE’s figure.
CPUC Reopens the IOUs’ Procurement Rulebook — Preapproval Frameworks Under §454.5 Face First Major Update in a Decade
An ALJ ruling asks parties to weigh the June 1 proposals of PG&E, SCE, and SDG&E to update their Bundled Procurement Plans — the Pub. Util. Code §454.5 frameworks that let specified transactions clear upfront standards and win preapproval instead of after-the-fact reasonableness review, last rebuilt in 2015. The utilities seek broader standing authority over RECs, RA (contracts up to 10 years), energy, fuel, and new CAISO day-ahead products, with batch quarterly reporting replacing per-transaction advice letters. A hybrid Energy Division workshop is set for mid-September; opening comments are due November 13.
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PG&E asks for RPS delivery terms up to five years, RA up to 10, and other electric and fuel transactions up to five; SCE proposes parallel authority plus Day-Ahead Market Enhancement products; SDG&E requests preapproval of short-term RPS deals and RA contracts of 10 years or less. Common questions cover standardized REC purchase/sale limits, absorption of the new unforced-capacity counting framework, treatment of CAISO imbalance-reserve and reliability-capacity products, excess RA sales, and GHG compliance instruments. The ruling also revisits the 2006 restrictions on utility participation in CAISO congestion revenue rights auctions — potentially the larger financial question, since loosening them could deepen auction competition and return more congestion revenue to customers. The utilities must file a matrix showing where their plans align and defend each difference.
Climate Credit Reform — ALJ Sets Ground Rules: Implementable Designs, Transparent Impact Data, Proceeds Held Constant
ALJ Sotero’s ruling establishes requirements for proposals to change the California Climate Credit, due September 14. Proposals may address the timing or number of distributions, calculation methodology, or eligibility, and must address equal treatment of bundled and unbundled customers, equity considerations, and implementation time, cost, and complexity — including whether changes could be implemented by 2028. Parties must meet and confer by August 28.
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Impact estimates are optional, lowering the barrier to submitting proposals — but any estimates must come with underlying spreadsheets or CSV files and source citations, hold total distributed allowance proceeds at the 2026 forecast level, use 2025 recorded consumption where available, and compare against the existing credit for typical CARE and non-CARE customers across climate zones for at least one large IOU. The design lets the Commission compare how each proposal would redistribute the existing credit rather than obscure effects through differing revenue assumptions. The ruling encourages “office hours” with utility staff and allows data requests, which utilities must answer within 10 business days.
Commissioner Houck PD Would Expand Tribal Consultation and Extend the Land-Transfer Policy to All IOU Property Sales
Commissioner Darcie Houck’s proposed decision revises the CPUC’s Tribal Consultation Policy and Tribal Land Transfer Policy: “early, often and meaningful” engagement on actions with tribal implications, escalation of inadequate consultations to the Executive Director, quarterly Tribal Information Forums starting 2027, and application of the land-transfer policy to all real-property dispositions by covered IOUs — including surplus property that would otherwise never receive Pub. Util. Code §851 review. Comments due September 2; earliest vote September 17, 2026.
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Utilities would obtain tribal contacts from the Office of the Tribal Advisor, notify relevant tribes of dispositions, and provide interested tribes a virtual data room with the property’s current appraisal, recorded easements, and related information; energy utilities would report dispositions quarterly. Disputes among tribes seeking the same property would run first through the tribes, then the CPUC’s ADR program. Implementation depends on the currently vacant, governor-appointed Tribal Advisor position; the PD does not extend the policy to telecommunications providers, require utilities to map all holdings, or reach harder issues of tribal taxation, tribal law, and energization delays.
Gas Research Oversight Splits — G-3623 Adopted Denying PG&E’s $1.95M 2024 Spend; G-3622 Held on the CEC’s $31.1M Drawdown
The Commission adopted Resolution G-3623 on September 17 and held Draft Resolution G-3622 to October 8. Both tighten CPUC oversight of ratepayer-funded gas research. Draft Res. G-3622 approves in part the CEC’s two $24 million RD&D plans but requires the agency to draw down $31.1 million in previously authorized, unspent funds first — limiting new ratepayer funding to $13.5 million — and bars hydrogen-related research pending a Commission determination on gas ratepayers’ role. Res. G-3623, as adopted, denies PG&E’s $1.95 million 2024 plan with no further resubmission authorized because the money was spent before plan approval, while authorizing $6.13 million (2025) and $7.87 million (2026) subject to revisions. PG&E may still record $611,440 in its balancing account for Commission-required planning, reporting and workshop costs.
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As adopted, G-3623 preserves $6.31 million for integrity-management research, $3.15 million for gas decommissioning and electrification planning tools and $3.15 million for clean fuels integration across the 2025 and 2026 budgets; it removes proposed evaluation and database funding and reduces administrative allocations to the 10% cap. PG&E must submit revised plans through Tier 2 advice letters within 60 days. Implementation of the 2025 plan must await approval of revisions demonstrating additional research value and avoiding duplication, while the 2026 plan may proceed as PG&E clarifies benefit metrics and accounts for AI and machine-learning costs in integrity-management research. Unspent funds return to ratepayers at the funding cycle’s close except amounts committed or encumbered for continuing work — so approval timing affects how much of the 2025 budget PG&E can commit before the balance becomes refundable.
G-3622, still pending, gives the CEC 90 days to revise both plans to improve financial reporting, demonstrate coordination with other research administrators, and address duplication. G-3623 permits no resubmission of the denied 2024 request and conditions the 2025–2026 budgets on revised plans within 60 days that distinguish PG&E’s work from similar SoCalGas research, quantify expected benefits, and — for 2026 artificial-intelligence work — account for energy, cloud-computing, data-storage, and processing costs while retaining human decision-making authority. Together the drafts establish a common oversight framework emphasizing unspent balances, measurable ratepayer benefits, and non-duplication; SoCalGas’s four pending 2024–2027 research plans suggest these standards will soon apply to the remaining major gas RD&D administrator.
Aliso Canyon — SoCalGas and Indicated Shippers Ask to Push the Next Biennial Assessment to June 15, 2028
The Indicated Shippers and SoCalGas filed a joint petition for modification to move the next Aliso Canyon Biennial Assessment Report deadline by one year, from June 15, 2027 to June 15, 2028. They argue the pending A.26-01-009 proceeding — which is reconsidering both the storage level and the D.24-12-076 Attachment A assessment methodology — is unlikely to finish before 2027, leaving Energy Division too little time to incorporate whatever methodological changes emerge.
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The petitioners also argue a 2028 report would better align with commercial and planning timelines: SoCalGas’s current Backbone Transportation Service contracts run through October 31, 2029; SB 1221’s second-round pilot deadline falls in January 2028; and the CEC’s next full IEPR is due in 2027. A June 2028 report would give market participants relatively current information approaching the next BTS cycle. A counterargument available to the Commission: Energy Division already moved the first report from June 15 to October 1, 2025 when it needed more time, and SoCalGas later received a separate extension before filing its application — so the CPUC could keep the biennial schedule and grant targeted relief when necessary rather than fixing the next report in 2028 now.
SoCalGas Southern System Reliability Purchases Approved — $5.5M Net Cost Recovery From Jan 1, 2027; Two Gas Rule 41 Provisions Loosened
Draft Resolution G-3620 approves SoCalGas’s Southern System reliability purchases and sales for the year ending September 30, 2025, finding compliance with Gas Rule 41 and allowing recovery of $5.5 million in net costs beginning January 1, 2027. It approves three purchases that fell outside Rule 41’s standard pricing rules, which SoCalGas attributed to limited suppliers, thin market liquidity, and an El Paso Natural Gas system constraint. It also replaces the baseload price benchmark with a safe harbor at 110% of the NGI Bidweek average for SoCal Border-Ehrenberg.
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The safe-harbor benchmark expires March 31, 2028 unless extended. A second revision lets SoCalGas contact five suppliers when it cannot obtain the three price offers normally required for spot purchases outside standard ranges; that provision expires June 1, 2029 unless extended. Cal Advocates warned the change could weaken competition and invite manipulation, and the Commission responded with conditions requiring SoCalGas to document supplier outreach, report response rates, and show the alternative process did not raise ratepayer costs. The resolution was adopted at the August 13 voting meeting.
SCE Authorized to Sell the 2.5 MW Lower Tule Hydro Plant — $40.2M Estimated Cost vs. $57.6M to Decommission, Saving Customers $17.4M
A proposed decision authorizes SCE to sell the century-old 2.5 MW Lower Tule Hydroelectric Plant in Tulare County, offline since 2017 fire damage, to Lower Tule Hydro LLC. Although SCE would pay the buyer $6.268 million to assume the facility, the decision finds the sale is the least-cost option at an estimated $40.2 million, versus $57.6 million to decommission and $101.8 million to repair and operate — a $17.4 million customer saving relative to decommissioning.
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The decision allows SCE to recover the sale’s estimated $25.1 million pre-tax loss from bundled and non-exempt departing-load customers through the Portfolio Allocation Balancing Account, while crediting customers for the plant’s removal from rate base and avoided maintenance costs. It denies without prejudice SCE’s request to include unspecified additional interest owed to the buyer in the transfer payment, because SCE did not provide adequate supporting calculations. The transaction remains subject to FERC approval of the license transfer, and SCE must submit final sale, tax, and rate adjustments within 60 days after closing. The item was adopted at the August 13 voting meeting.
Sempra Authorized to Create an Intermediate Holding Company Above SoCalGas and SDG&E — Exempted From §854 Review Under §853(b)
A proposed decision authorizes Sempra to create Sempra California LLC as an intermediate holding company above the direct parents of SoCalGas and SDG&E. The decision calls it a “close question” whether the reorganization requires Pub. Util. Code §854 review, but exempts the transaction under §853(b), finding Sempra will remain the utilities’ ultimate parent.
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Approval comes with ring-fencing conditions: SoCalGas and SDG&E must maintain separate books and assets, conduct affiliate transactions at arm’s length, preserve the Commission’s access to corporate information, and remain financially insulated from their affiliates. The §853(b) exemption route avoids the fuller public-interest review that a §854 transfer-of-control proceeding would require. The item was adopted at the August 13 voting meeting.
PG&E 2027 GRC — PD Would Make the Revenue Requirement Effective January 1, 2027 Though a Phase 1 Decision Is Not Expected Until May 2027
A proposed decision would let PG&E make whatever revenue requirement the Commission ultimately approves in its 2027 General Rate Case effective January 1, 2027, even though the schedule sets only a tentative May 2027 Phase 1 decision date. The uncontested proposal is meant to keep customers and shareholders indifferent to the timing of the final decision and to avoid retroactive-ratemaking concerns. Earliest Commission consideration is October 8, 2026.
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The PD would authorize PG&E to use three existing memorandum accounts — electric, gas distribution, and gas transmission and storage — to track the difference between 2023 GRC authorized revenues and the 2027 amounts. Any resulting over- or under-collections would accrue interest at the Federal Reserve’s three-month commercial paper rate and be reconciled after the GRC decision. The memorandum-account authorization triggers if the Commission issues its decision after January 1, 2027, which given the May target is effectively certain. The PD says nothing about whether PG&E’s underlying GRC request is reasonable.
Res. E-5480 Adopted — Energy Division Keeps Control of Distribution-Equity Modeling; IOUs Must Report Five Customer Populations Separately
Adopted September 17, Resolution E-5480 approves with modifications the IOUs’ proposals for measuring equity in annual distribution planning under D.24-10-030. It finds the utilities complied but that their proposals alone cannot produce consistent, comparable results, and would require PG&E, SCE, and SDG&E to report five populations separately: CARE, FERA, Medical Baseline, Tribal community members, and customers in SB 535 disadvantaged communities. Utility data is due October 16, 2026, with the first public report in Q3 2027.
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PG&E and SCE had proposed a shared regression-based approach examining available grid capacity and project initiation, while SDG&E proposed load-growth and project-initiation metrics using a broader binary classification of circuits; the resolution concludes combining the customer groups could obscure differences among them and double-count customers. Energy Division would instead apply a common analytical framework examining forecast load growth, available circuit capacity, and the likelihood that identified distribution projects advance, with the models serving as screening tools for potential disparities rather than findings of inequity. The resolution rejects CCA and environmental-group arguments that D.24-10-030 required verbatim adoption of five Commission-identified metrics. Energy Division could revise the required data template without another resolution on 90 days’ notice; customer-sensitive inputs stay confidential while aggregated results are public. The draft declines to add disadvantaged-community information to interconnection maps or set a deadline for addressing capacity disparities, leaving energization timelines to R.24-01-018.
SCE 2026 RAMP — Scoping Memo Targets Benefit-Cost Ratios, Mitigation Alternatives, Risk-Averse Scaling, and Wildfire Tail Risk
Commissioner Harada issued a scoping memo for SCE’s 2026 Risk Assessment Mitigation Phase filing, focusing on whether SCE properly built its benefit-cost ratios, weighed reasonable alternatives to its mitigation plans, and justified its risk-averse scaling functions and wildfire tail-risk treatment. The Commission will also examine SCE’s proposed alternatives to its best-practice quintile tranching method for cyberattack, seismic, hydro dam failure, and physical security risks. Opening comments are due November 18, 2026, replies December 12, 2026.
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The RAMP filing is the analytical predicate for SCE’s 2029 General Rate Case, so scoping in benefit-cost ratios, mitigation alternatives, risk-averse scaling, and wildfire tail-risk treatment preserves the Commission’s ability to challenge how SCE converts risk estimates into proposed ratepayer spending before the rate case is filed. The comment schedule runs into late 2026, well ahead of the GRC. Intervenors including TURN raised threshold questions during the protest period about whether SCE’s portfolio optimization satisfies the binary optimization requirement adopted in D.25-08-032.
PG&E — $2.6B Capital-Structure Question Held a Third Time: Competing PD (Deny All) vs. Reynolds Alternate (Exempt DWR Loan)
The Commission again postponed PG&E’s request to exclude roughly $2.6 billion from its 52%-equity capital-structure calculation — 2019 Kincade Fire equity charges (~$1.2B), 2021 Dixie Fire debt (~$277M), and the $1.4 billion forgivable DWR loan for the Diablo Canyon extension. The ALJ’s proposed decision would deny all relief; President Reynolds’ alternate, issued July 31, would grant in part, exempting only the DWR loan. Both items were held from the August 13 agenda to September 3, 2026 for a Pub. Util. Code §311(e) requirement.
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The proposed decision rejects PG&E’s request on three grounds: the wildfire costs equal only about 0.6% of equity, below the 1% materiality threshold for an Affiliate Transaction Rule Section IX-B waiver (PG&E’s 2020 waiver covered $8.9 billion; SCE’s comparable approved request was roughly 10% of equity); aggregating the unrelated Kincade and Dixie events is improper; and a forgivable state loan is not an adverse financial event. It also credits TURN’s showing that PG&E’s actual equity ratio has run 7–10 percentage points below its authorized 52% since 2021, generating an estimated $2.4 billion in shareholder profits funded by ratepayers. The Reynolds alternate would exempt the DWR loan and require a capital-structure true-up analysis and loan-forgiveness status reporting in PG&E’s next cost-of-capital application. This is the third hold, after July 2 and July 16; Cal Advocates held ex parte meetings with President Reynolds’ office in the week before the meeting. Items 3/3A on the August 13 agenda; earliest vote September 3, 2026.
PG&E–Google 250 MW San Jose Data-Center Energization Held a Second Time (Houck, “Further Review”)
Commissioner Houck held the draft resolution approving, with modifications, PG&E’s “exceptional case” agreement to energize Google’s 250 MW transmission-level (230 kV) data-center load in San Jose — the first major test of PG&E’s large-load energization framework — to the September 3, 2026 meeting for further review. The draft would limit annual refunds of Google’s capital advance to annual net revenues received from the customer plus an income-tax-component adjustment, route broader transmission network-upgrade costs through a Tier 2 advice letter, and require separate refundable and non-refundable cost-cap calculations.
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The resolution disposes of PG&E Advice Letter 7785-E, filed December 18, 2025. It was first held at the July 16 meeting by staff; the August 13 hold is Commissioner Houck’s. The refund-limiting mechanism responds to ratepayer-risk concerns aired in the parallel Rule 30 large-load cost-allocation fight in A.24-11-007, and the framework now sits alongside FERC’s June 18, 2026 show-cause order questioning whether CAISO tariffs adequately address large and co-located loads — a proceeding that could federalize parts of what Res. E-5455 addresses. Item 4 on the August 13 agenda. The resolution was held again on September 3 and September 17, and is now scheduled for October 8. The current draft requires Google to provide an additional refundable capital advance of $600,000/MW — as much as $150 million at 250 MW.
PG&E — Short-Term Borrowing Cap Raised $1 Billion to $9.5B, Half the Request
The Commission took up on its August 13 consent agenda the decision granting PG&E a $1.0 billion increase in short-term debt authority — from $8.5 billion to an aggregate cap of $9.5 billion — half of the $2 billion increase PG&E requested. The authority is not effective until PG&E pays $506,000 in fees under Pub. Util. Code §§1904/1904.1, and the decision closes the proceeding. The adopted decision number had not yet posted as of publication.
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PG&E framed the increase as working-capital flexibility given wildfire-claim payment timing and the scale of its capital program; the application was tied at filing to a $1 billion reserve related to the winter gas price cap. The proposed decision (Commissioner Houck, ALJ Seybert) was held from the July 16 meeting by Commissioner Baker before going to vote August 13. Item 5 on the August 13 agenda.
Southwest Gas — 2026 GRC Decision: $32.6M Revenue Increase, About 25% Below Request; 22.36% Southern California Rate Increase
After a July 16 hold, the Commission took up Southwest Gas’s Test Year 2026 general rate case decision at its August 13 meeting, moved from consent to the regular agenda for discussion. The decision adopts a 50.0% debt / 50.0% equity capital structure, a 10.00% return on equity, and overall rates of return of 7.07% (Southern California) and 7.17% (consolidated Northern California / South Lake Tahoe), producing rate increases of 22.36% in the Southern California jurisdiction and 5.17% in Northern California / South Lake Tahoe — a $32.6 million revenue increase, roughly $11.05 million (25%) below the company’s request.
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Authorized operating revenues: $173.18 million Southern California, $41.26 million Northern California, and $32.71 million South Lake Tahoe. The decision (Commissioner Baker, ALJ Jeffrey Lee) resolves the cost-of-capital issues at Southwest Gas’s proposed 50% equity layer with a 10.0% ROE, closes the proceeding, and applies to the January 1, 2026 test year, making the adopted rates retroactive. The item was one of the four major energy items held from July 16 (by Commissioner Harada). Next steps: posting of the adopted decision number and implementing advice letters. Item 6 on the August 13 agenda.
PG&E — $22 Million Mosquito Fire Consent Order Adopted
The Commission adopted Resolution SED-13, approving the Administrative Consent Order between its Safety and Enforcement Division and PG&E resolving the investigation of the September 2022 Mosquito Fire, which burned 76,788 acres in Placer and El Dorado counties and destroyed 78 structures. PG&E shareholders pay a $21 million penalty to the State General Fund plus $1 million for an independent third-party review of the utility’s Transmission Centralized Inspection Review Team.
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SED found violations of General Order 95 rules on the design, construction, and maintenance of overhead lines; its investigation also alleged PG&E delayed reporting the fire by two days and destroyed equipment that could have served as evidence. The independent review will assess the Transmission Centralized Inspection Review Team’s policies and procedures, GO 95 compliance, and documentation practices, and produce actionable recommendations. The matter was resolved as an Administrative Consent Order under the Res. M-4846 enforcement framework without a formal Order Instituting Investigation. PG&E’s most recent 10-Q carries a roughly $400 million loss estimate for the Mosquito Fire, against $1.3 billion for Kincade and $2.2 billion for Dixie. Item 15 on the August 13 agenda.
SCE — Fire-Map PD Adds 47 Areas (~208 sq mi) to the High Fire-Threat District, Denies All 61 Proposed Removals — Held to Oct 8
A proposed decision would partially grant SCE’s petition to modify D.17-12-024: it approves adding 47 areas in SCE territory to the High Fire-Threat District map but denies the removal of all 61 areas SCE proposed to de-designate. It also directs the Safety Policy Division to hold a 2027 workshop on future map-modification processes and would close R.15-05-006, the original 2015 fire-map rulemaking. The added areas total about 208 square miles. Held from September 3, the item was held again on September 17 and is now scheduled for October 8.
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Status update (Sep 2026): this item was
not approved at the September 3 voting meeting. Commissioner Darcie Houck held it until
September 17 for further review.
Held item.
Per SCE’s petition, the combined changes would have netted an increase of roughly 40 square miles (0.07%) in HFTD area; the proposed decision accepts the additions while rejecting the de-designations. HFTD designation drives enhanced vegetation-management, inspection, and hardening obligations, so boundary changes flow directly into wildfire-mitigation spending. Assigned to Commissioner Douglas; quasi-legislative. Rule 14.3 opening comments run to about August 20; earliest vote is the September 3, 2026 business meeting.
PG&E Rule 30 Data-Center Case Reopened for Comment on FERC’s Large-Load Show-Cause Order
An ALJ ruling in PG&E’s Electric Rule 30 application — the transmission-level retail tariff for data centers and other large loads — reopened the record for comments on FERC’s June 18, 2026 show-cause order to CAISO and its participating transmission owners (Docket EL26-71-000), which preliminarily found existing tariffs may be unjust and unreasonable for lacking clear provisions on studying service for loads of 50 MW or more, deterring speculative requests, mitigating cost shifts from network upgrades, and co-location terms. Limited opening comments are due August 25, replies September 4, after which the record submits.
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PG&E filed the Rule 30 application November 21, 2024; D.25-07-039 granted interim implementation in July 2025 while deferring all refund and cost-allocation questions, and evidentiary hearings ran in September 2025 and April 2026 with reply briefs May 22, 2026. On the core cost-allocation fight, PG&E backs the Resolution E-5420 75%-refund approach; TURN proposes an interim load-development fee of $667/kW for loads of 25 MW or more; Cal Advocates has floated a $50 million flat-fee / revenue-cap alternative; Sierra Club and NRDC argue beneficiary-pays; CalCCA settled most of its issues in May. The Silicon Valley Power 230 kV line at the center of the case is estimated at $593–858 million. FERC’s order — alongside its October 2025 large-load ANOPR (RM26-4-000) — could federalize parts of what Rule 30 and Res. E-5455 address; the Independent Energy Producers Association moved for party status August 13.
Avoided Cost Calculator PD: Updated 2026 Values for DER Cost-Effectiveness
A proposed decision in the demand-flexibility rulemaking would adopt updates to the Avoided Cost Calculator beginning with the 2026 ACC, intended to better reflect building and vehicle electrification and growing renewable penetration in how PG&E, SCE, and SDG&E distributed-energy-resource programs are valued. Opening comments are due August 20, 2026, with replies five days later.
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The ACC is the common yardstick for cost-effectiveness across DER programs — energy efficiency, demand response, self-generation, and electrification incentives — so revised avoided-cost values propagate into every program evaluation that relies on them. Trade coverage in the comment window flagged that the updated values could reduce the calculated benefits of some electrification programs, which is likely to be a focus of the August 20 opening comments. Earliest vote is the September 3, 2026 business meeting.
CPUC - Clean Miles Standard Phase 2 Proposed Decision: Keeps Waymo and Zoox Robotaxis Exempt, Adds Low-Income Driver EV Incentives, and Declines a Citation Program
Commissioner Christine Harada’s proposed decision resolves the Phase 2 issues in the Clean Miles Standard Program (SB 1014), the CPUC mandate that ride-hail and other passenger platforms cut greenhouse-gas emissions per passenger-mile by moving drivers to zero-emission vehicles. The PD keeps the full exemption for autonomous-vehicle passenger carriers (Waymo, Zoox) pending the state’s 2031 zero-emission AV mandate, codifies added EV incentives for low- and moderate-income drivers, and declines to adopt a citation/enforcement program for the annual GHG targets. The decision closes the proceeding and is eligible for a Commission vote no earlier than September 3, 2026.
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The Clean Miles Standard (SB 1014) is implemented by the CPUC and its GHG targets are set by CARB; Phase 1 (D.24-03-001, March 2024) established the first targets for transportation network companies (Uber, Lyft). This Phase 2 decision resolves the entities and mechanics left open in Phase 1.
Autonomous-vehicle passenger carriers: the PD keeps AV carriers exempt from (1) annual advice-letter filings, (2) the per-trip CMS regulatory fee, (3) annual GHG emission-reduction plans, and (4) quarterly and annual CMS data reporting, reasoning that AV fleets use company-owned vehicles with no drivers to subsidize and that Vehicle Code Section 38750(i) already requires all model-year 2031-and-later AVs on deployment permits to be zero-emission. Waymo, Zoox, and SEIU supported the exemption; Lyft opposed it, arguing AVs pose the same environmental impact as TNCs and should not be exempt.
Other Phase 2 holdings: the decision codifies additional EV incentives for low- and moderate-income drivers, addresses transportation charter-party carriers, GHG-target optional credits, rental and multiple-incentive rules, and lays out a process for winding the program down once targets are met. Agenda ID #24394 (Quasi-Legislative); proposed decision of Commissioner Christine Harada, transmitted by Chief ALJ Michelle Cooke.
CPUC Lowers the Extreme-Heat Disconnection Trigger to 90°F: Res. E-5468 Approves Four-IOU Advice Letters Under D.25-06-012
At its July 16 voting meeting the Commission adopted Resolution E-5468, approving with modifications the Tier-3 advice letters filed by PG&E, SCE, SDG&E, and SoCalGas to implement D.25-06-012. The resolution replaces the prior 100°F heat trigger for residential disconnections with a CalHeatScore Level 2 trigger and an interim 90°F fallback, tightening protections against shutoffs during extreme heat.
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The four advice letters (SCE 5707-E, PG&E 7783-E, SDG&E 4770-E, SoCalGas 6570-G) were filed December 17, 2025 under Ordering Paragraph 4 of D.25-06-012. The prior 100°F threshold traces to D.20-06-003. No fixed dollar amount is approved; the resolution authorizes the utilities to record incremental compliance costs in their Disconnections Memorandum Accounts and requires PG&E, SCE, and SDG&E to file annual Tier-1 arrearage-impact reports for three years. Item 18 on the July 16 agenda (Agenda ID 24329).
PG&E Hinkley S-238 Compressor CPCN: Proposed Decision Would Grant Withdrawal of a $93.5M Project Already Under Construction
A proposed decision by ALJ Zhen Zhang would grant PG&E's motion to withdraw its Certificate of Public Convenience and Necessity application for the $93.5 million Hinkley Station S-238 compressor-replacement project. PG&E began construction in January 2026 under a General Order 177 emergency exemption, then moved to withdraw the CPCN in February. Earliest Commission action: August 13, 2026.
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PG&E commenced the project January 20, 2026 under the GO 177 Section IV.B.c emergency exemption, completed a Final Initial Study / Mitigated Negative Declaration in January 2026, then filed to withdraw the application February 4, 2026. The proposed decision would close the proceeding. Agenda ID 24368; Assigned Commissioner Matthew Baker. The item is not final and is set no earlier than the August 13, 2026 voting meeting.
PG&E - Northern San Joaquin 230 kV Transmission CPCN Adopted: $198.8M Reliability Upgrade Doubling Local Capacity for ~38,000 Lodi-Area Customers
At its July 16 voting meeting the Commission signed D.26-07-042, granting PG&E a Certificate of Public Convenience and Necessity for the Northern San Joaquin 230 kV Transmission Project, a reliability upgrade that loops the Brighton-Bellota line through Lockeford Substation and adds a new double-circuit 230 kV line to the new Thurman Switching Station. The decision sets a $198.8 million cost cap (14% contingency) with a March 2029 target, and roughly doubles local load-serving capability for about 38,000 PG&E and Lodi Electric Utility customers.
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The adopted decision grants some of PG&E’s requested revisions to biological mitigation measures while keeping a 1,640-foot burrowing owl survey buffer, California tiger salamander work stoppages, wetland O&M protections, and bat roost obligations. The project was reviewed under a Final Environmental Impact Report published December 2024. The CPCN clears construction to begin, with the loop-in at Lockeford Substation and the new Thurman Switching Station at Lodi Electric Utility’s Industrial Substation forming the backbone of the added 230 kV capacity. Item 14 on the July 16 agenda; the only major PG&E item that was signed rather than held to August 13.
CPUC - High DER Track 2 Workshop Ruling: DER Orchestration and TSO-DSO Coordination Reports; Opening Comments July 27
A new CPUC ruling enters two Track 2 workshop reports into the record of the Commission's High DER proceeding (R.21-06-017), with opening comments due July 27 and replies due July 31. The reports cover a May 21 workshop on distribution system operator-led DER orchestration and the June 5 TSO-DSO coordination workshop held with the CAISO in Folsom.
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Energy Division prepared the DSO-led orchestration report; the CAISO and the three large electric IOUs prepared the TSO-DSO coordination report. The ruling's first question invites parties to identify factual inconsistencies or needed clarifications in either account. The workshops examined how utilities could use batteries, EVs, smart thermostats, water heaters, and other flexible loads to meet location-specific grid needs, defer capital projects, accelerate energization, and improve reliability.
The record spans DER visibility, communications standards, dispatch/aggregator roles, valuation, incentives, utility readiness, and the data CAISO needs from distribution operators to forecast and operate the system. The ruling's
18 questions ask parties to address sequencing, working-group scope, pilot integration, Advanced Metering Infrastructure and DERMS capabilities, customer-owned technology fit, circuit-level flexibility modeling, and specific opportunities for ratepayer savings.
Where parties stand: Even the utilities are not pressing for immediate full-scale DER orchestration applications.
SCE recommends an advice-letter pathway with balancing or memorandum accounts for iterative pilots ahead of its next GRC.
PG&E proposes a Tier 2 advice letter and memorandum account covering a 2026-27 trial phase, piloting through 2030 and scaling afterward.
SDG&E proposes to adopt the framework adopted first, applications filed only when readiness justifies them, and no Commission-mandated timeline.
Cal Advocates argues the CPUC should build the framework before deciding whether applications are needed at all.
"Open access" definition: Universal Devices pointed to PG&E's acknowledgment at a February Track 3 workshop that its current aggregator interface is proprietary and non-standardized.
CalCCA urged the Commission to evaluate an independent marketplace operator, citing Piclo's UK track record and 2025 U.S. launch. The Utility Consumers' Action Network (UCAN) called for procurement of a statewide flexibility platform and argued that each additional year of piloting risks locking in distribution upgrades that an operating flexibility market could defer, given the IOUs' forecast of
$42 billion to $48 billion in distribution investment through 2040.
The CPUC wants quantified showings: Question 17 requires explicit examples of cost reductions and how they change at scale; Question 13 requires dependability accounting grounded in actual customer behavior and resource availability.
CPUC - Assigned Commissioner Houck Proposes Broader Flexible Service Connections; SDG&E Static Offering Sought; Comments July 21
The CPUC is seeking comments on an Assigned Commissioner's proposal from Commissioner Darcie Houck to expand flexible service connections in its High DER grid-modernization proceeding. The proposal would move constrained circuits away from being automatic upgrade triggers and toward being managed service conditions - customers could connect under defined operating limits while utilities, DERs, and grid-edge tools manage capacity constraints. Opening comments July 21, replies July 28.
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The proposal aims to connect customers to the distribution grid faster by using existing capacity more efficiently. The ruling frames flexible connections as a way for DERs, power control systems, and
DERMS-adjacent tools to provide near-term energization options while maintaining safety and reliability and containing ratepayer costs.
The investor-owned utilities must respond by
July 14 to questions on grid-edge DERMS efforts (PG&E's technology-provider workshops and any SCE or SDG&E work using local measurement, computation, and power control systems).
All parties must file initial comments by
July 21 and replies by
July 28 on the overall proposal, covering: (1) implementation feasibility; (2) cost-and-benefit tracking; (3) safeguards against proprietary lock-in; (4) safety issues; and (5) a recommendation directing SDG&E to stand up a static flexible service connection offering aligned with requirements
already imposed on PG&E and SCE. A separate question seeks input on cybersecurity testing and certification programs.
Procedural context: The CPUC is moving flexible interconnection past the pilot stage. A 2026 decision (
D.26-02-025) already ordered PG&E and SCE to stand up static flexible service connection offerings. This ruling extends the framework by circulating Houck's proposal for comment, proposes the same static offering for SDG&E, and asks how to measure whether any of it saves ratepayers money. Developers, large-load customers, aggregators, CCAs, and the utilities themselves all have direct financial exposure to how those limits get set. The Commission has noted in prior filings that Enterprise DERMS does not scale for many of these scenarios and that grid-edge planning, progress, and costs are not yet uniformly reported.
CPUC - Customer Reliability Report PD: Unified Annual Filing With Granular Circuit-Level Outage Record; SAIDI/SAIFI/CAIDI/MAIFI Added
A new proposed decision would require PG&E, SCE, and SDG&E to file a unified annual "Customer Reliability Report" with the CPUC's Safety Policy Division beginning in 2027, due within 30 days after July 15 each year. The filing would absorb the existing Annual Electric Reliability Report unchanged and consolidate outage information now spread across multiple filings. Earliest CPUC consideration: August 13.
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The PD’s template expands the utilities’ proposal. For each outage, they would report: percentage of circuit overhead vs. underground; conductor type (bare, covered, or insulated); start and end times; whether the event was a Public Safety Power Shutoff or occurred on a Fast-Trip-enabled circuit; and counts of Medical Baseline and essential customers. PSPS and Fast-Trip events would be categorized separately from other unplanned outages.
Utilities would explain how they notify customers before, during, and after outages, with separate reporting for maintenance outages, de-energizations, weather events, and Fast-Trip interruptions. Reports would delineate communications by customer class and describe outreach to public safety partners and medically vulnerable customers.
Metrics added: The template adds
SAIDI,
SAIFI,
CAIDI, and
MAIFI to the utilities' proposed
CEMI and CELID measures. Metrics would be reported with and without "Major Event Days" and sortable.
The PD retains
annual reporting over party proposals for monthly, quarterly, or semiannual filings. Utilities file by advice letter, with SPD preparing a resolution for CPUC consideration. Every three years beginning in 2029, the utilities may propose limited template updates.
Procedural context: The PD converts reliability reporting from a systemwide scorecard to a granular record of outage location, duration, grid conditions, and notice. It does not adopt a new reliability standard or spending mandate. The schema may inform later rate cases, wildfire proceedings, and distribution-investment reviews by making outage patterns traceable to specific circuits, infrastructure types, and customer groups.
CPUC - DR Bridge-Year Funding: ALJ Ruling Removes Testimony and Hearings; ELRP Budget Position Stated on the Record
In a July 7 email ruling in the CPUC's Demand Response rulemaking (R.25-09-004), ALJ Brandon Gerstle eliminated testimony, evidentiary hearings, and briefs from the schedule for the DR bridge-year funding issue - concluding the written record is sufficient for a decision. Cal Advocates was the only party requesting testimony, seeking to oppose an increase in the Emergency Load Reduction Program (ELRP) budget. Gerstle said he is not inclined to change that budget at this time.
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Procedural context: The ruling closes the evidentiary phase of the bridge-year funding dispute and positions the matter for a proposed decision on the written record. Cal Advocates’ request for testimony was denied; ALJ Gerstle’s stated position on the ELRP budget aligns with the substantive outcome Cal Advocates sought. The DR bridge-year sits alongside the four resolutions on the July 2 voting agenda (E-5456 SCE CBP-Elect direct enrollment approved; E-5444 SDG&E residential CBP denied; E-5450 PG&E ART partial approval; E-5451 PG&E BIP mid-cycle updates) within the Commission’s current DR program scope review ahead of the 2028-2033 cycle.
SDG&E - Residential Capacity Bidding Program: Draft Resolution E-5444 Recommends Denial (July 2 Agenda)
Draft Resolution E-5444 is expected to be adopted at the July 2, 2026 voting meeting (Item 19), rejecting SDG&E's proposal to create a residential Capacity Bidding Program and associated budget transfers. The rejection cuts off a planned residential Demand Response expansion channel; the Commission's rationale (per the draft) rests on penalty design too weak vs the existing model plus missing Resource Adequacy compliance and load-impact filings required of supply-side resources.
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Res. E-5444 is one of a four-part Demand Response package first previewed at the June 3, 2026 CPUC voting meeting agenda. The other three DR draft resolutions (E-5456 SCE CBP-Elect direct enrollment, E-5450 PG&E ART partial approval, E-5453 Joint PG&E+SCE AutoDR update) either advanced with modifications or received approval. The SDG&E residential CBP rejection is a stricter standard: the Commission is explicit that residential DR expansion or DER-based supply-side programs will not be approved absent full documentation matching supply-side resource requirements. Residential DR aggregators (Sunrun, Tesla, Renew Home) have separately offered
16.8 GW of DER capacity to utilities as of Jun 24; the Commission's
Res. E-5444 stance clarifies that CPUC residential DR expansion will follow supply-side compliance, not aggregator-market signals.
SB 884 Undergrounding — PG&E Resists Milestone-Specific Benefit-Cost Accuracy Bands, Applies a Flat 30% Uncertainty Factor
PG&E, SCE, and SDG&E responded to ALJ DeAngelis’s June 18 ruling on how benefit-cost ratios will be built and verified in SB 884 Phase 2 undergrounding applications. PG&E proposes AACE-style cost-estimate maturity classes (early projects −50%/+100%, maturing to −5%/+10%) but declines milestone-specific BCR accuracy ranges, instead applying a flat 30% uncertainty factor when comparing mitigation alternatives. SCE said it has no current plan to submit an electrical undergrounding plan.
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PG&E treats cost estimates and risk-reduction estimates as separate categories with separate standards, arguing wildfire-risk modeling never reaches comparable precision. Its O&M assumptions draw mainly on 2023 GRC forecasts and normalized historical data, assuming undergrounding eliminates PSPS-related and vegetation-management O&M, cuts patrols, inspections, and emergency work by roughly 90%, and modestly reduces routine maintenance. PG&E would not track avoided O&M savings project by project after construction — only periodic program-level GRC review — calling them counterfactual over 48–55 year asset lives; SDG&E breaks with PG&E and commits to tracking actual project-level O&M costs post-construction. For evacuation constraints, tree-strike exposure, and PSPS geography, PG&E says engineers will conduct granular reviews outside the systemwide risk model, potentially supporting targeted or hybrid designs, qualifying only if a hybrid stays within the 30% uncertainty band and outperforms full undergrounding.
Reynolds Ruling Reorients the Climate Credit Toward Affordability — Floats Tiered Credits (1×/2×/3×) and Climate-Zone Variants
CPUC President Reynolds issued a ruling directing the California Climate Credit toward affordability, electrification, and usage-based need, stating that the Commission’s earlier principle of withholding the credit during high-cost periods to preserve the carbon price signal no longer reflects statutory direction. One concept ties credit count to baseline usage — one credit below baseline, two above, three for CARE customers above baseline; another varies credits by climate zone. Opening comments were due July 24, replies July 31, with a workshop August 10 and party proposals September 14.
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The ruling cites AB 1207, Executive Order N-5-24, and a recent Commission decision as pointing toward greater assistance during high-cost periods for high-usage and low-income customers, and asks whether a purely volumetric cents-per-kWh credit would better serve affordability and electrification. On the gas side, CARB’s 2026 Cap-and-Invest updates shift an increasing share of gas allowance value to electric utilities beginning in 2028, reaching 70% by 2031, with the remaining 30% reserved primarily for low-income gas customers; Reynolds would leave gas credit timing, eligibility, and distribution unchanged before 2028, then allocate the reserved 30% among CARE gas customers and the shrinking remainder among non-CARE customers. The ruling acknowledges a distributional risk that added assistance could disproportionately benefit higher-income customers in hotter climate zones. This ACR is the predecessor to the August ALJ ruling setting proposal requirements.
Draft Res. E-5463 Replaces Ad Hoc LCFS Advice Letters With a Fixed Annual Cycle; Equity-Spending Requirement Rises to 75%
Draft Resolution E-5463 would streamline how PG&E, SDG&E, and SCE seek approval for programs funded by Low Carbon Fuel Standard credit proceeds, replacing the current ad hoc advice-letter process with a fixed annual cycle: implementation plans due January 31, budget extensions through the September 30 forecast advice letter, with the prior year’s budget remaining in effect if that letter is unresolved at year-end. The draft treats LCFS verification costs as overhead and qualifies medium- and heavy-duty electrification infrastructure as equity spending when it meets CARB requirements. It was approved with modifications at the August 13 voting meeting.
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The draft accepts that truck emissions benefits may occur along travel corridors rather than only at a vehicle’s domicile or charging location, meaning a charging site need not sit inside a disadvantaged community to count as equity spending if the vehicles it serves operate in one. The provisions respond to CARB’s revised LCFS rules, which shifted Clean Fuel Reward funding from light-duty EV rebates toward medium- and heavy-duty vehicle incentives, raised equity-spending requirements to 75% for large and medium IOUs, reduced required utility remittances to the statewide program, expanded the list of preapproved holdback projects, and added third-party verification requirements beginning in 2027. The annual filing cycle itself is primarily administrative; the substantive change originates with CARB.
Resource Adequacy — Final Track 1 Decision Adopts Local Capacity Requirements of 23,618 MW (2027) Rising to 25,480 MW (2029) and the UCAP Framework for 2028
The Commission adopted its final Track 1 Resource Adequacy decision on July 2, setting CAISO Local Capacity Requirements at 23,618 MW (2027), 24,545 MW (2028), and 25,480 MW (2029), with the LA Basin climbing from 6,823 MW to 7,721 MW, and adopting 2027 Flexible Capacity Requirements peaking in March at 30,378 MW system-wide (CPUC-jurisdictional share 29,063 MW). The Unforced Capacity (UCAP) framework takes effect for the 2028 RA compliance year for dispatchable thermal, nuclear, geothermal, and non-hybrid storage, with accreditation reduced by each resource’s EFORd during RA Measurement Hours.
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EFORd is calculated from the best three of the prior four years of CAISO outage data; new resources receive class-average values until unit-specific history accumulates, and thermal generators get weather-normalized ambient-temperature derates from NOAA typical-weather-year data. Seven implementation questions move to Track 2: hybrid resource methodology, the Must-Offer Obligation basis once UCAP replaces qualifying capacity, EFORd for the energy component of storage, fifth-hour foldback, flexible RA interaction, Slice-of-Day template integration, and the four-hour discharge requirement for storage RA eligibility. The revised storage qualifying-capacity foldback formula takes effect for the 2027 compliance year rather than immediately, after AReM and PG&E argued immediate adoption would strand 2026 procurement. Long-duration storage (≥8 continuous hours) gains a first-ever RA counting pathway beginning 2027, countable across the full 24-hour Slice-of-Day using a Forward Charge Period multiplier from 2× to 8×. The decision declines CalCCA’s hourly load-obligation trading mechanism, citing Energy Division’s Transactability Report; Commissioner Baker voted yes but called Slice-of-Day products “chunky” and asked colleagues to keep an open mind toward a market “around the edges.”
SB 1221 — CPUC Adopts Gas Decommissioning Pilot Framework: 30 Pilots Statewide, 16 in Round One, First Applications Due April 1, 2027
The Commission adopted a final decision 4–0 establishing the application process for SB 1221 neighborhood decarbonization pilots — the first formal pathway for gas corporations to replace gas service with zero-emission alternatives and decommission the underlying distribution system. The program is capped at 30 pilots statewide, with round one limited to 16: seven each for PG&E and SoCalGas/SDG&E, one reserved for Southwest Gas, and one for smaller gas corporations. The adopted decision drops the proposed decision’s pre-filing 67% consent screen, requiring only a reasonable expectation of obtaining consent before filing.
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Round-one applications are due April 1, 2027; round two January 15, 2028; round three (if slots remain) June 1, 2028. Binding consent from owners of at least 67% of properties is still required after approval before capital is invested. Each pilot must show avoided gas infrastructure costs exceed the zero-emission alternative’s cost on an NPV basis using the utility’s WACC as discount rate. Customer offerings must include a no-cost option for all appliances, upgrades, and remediation; behind-the-meter costs must be treated as expenses rather than rate-of-return-earning capital, amortized over no more than ten years. Shareholder incentives, data collection, reporting, and evaluation are deferred to Track 4. Commissioner Douglas said Energy Division will issue another staff proposal before the first deadline and flagged the SB 1221 obligation-to-serve determination; Commissioner Baker warned that gas-to-electric conversion imposes upfront electric-system costs on electric customers. Commissioner Harada was absent.
Aliso Canyon — Scoping Memo Puts the 68.6 Bcf Limit and a Possible 10 Bcf Reduction in Play; Inventory Increase Ruled Out of Scope
Commissioner Douglas’s scoping memo in SoCalGas’s Aliso Canyon application sets two questions: whether the maximum inventory should remain at 68.6 Bcf or be reduced, and whether the Commission should revise Attachment A, the modeling framework governing future biennial assessments. SoCalGas’s request for an inventory increase was ruled out of scope because a higher inventory could require a higher maximum operating pressure that CalGEM has not been asked to evaluate. Intervenor testimony was due August 20, rebuttal September 17, and intervenor rebuttal October 8.
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In a footnote the scoping memo observes that the forward prices used in the analysis reflect the current storage limit and that reducing capacity “would likely cause the forward prices to rise.” The Biennial Assessment itself acknowledges its economic analysis does not predict how a lower inventory limit would affect gas prices, which together with the footnote gives SoCalGas a commissioner-supplied premise for challenging the rate impacts of staff’s recommended 10 Bcf reduction. Attachment A directs Energy Division to evaluate demand, hydraulic reliability, seasonal gas-system reliability, and economic conditions when recommending whether the limit should change — so putting it in play means the docket will determine not only whether the limit drops but how future reduction decisions are modeled. Prior filings include June 1 comments from Sierra Club and Cal Advocates challenging the case for higher inventory.
Climate Adaptation — Houck Opens Comment on a Four-Year Community Engagement Framework and the Utilities’ Climate Lexicon Report
Commissioner Houck entered two items into the record of the Climate Change Adaptation rulemaking and opened them for comment: an Energy Division proposal replacing point-in-time Community Engagement Plans with a four-year Community Engagement Framework tied to each Climate Adaptation Vulnerability Assessment — requiring three public touch points per cycle — and the utilities’ Climate Lexicon Working Group Report. Opening comments were due July 30, replies August 10.
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The framework would require a publicly transparent advisory-group process, a separate Tribal engagement track, posted recordings and materials, and a documented feedback loop showing how community input changed the CAVA or why it was not incorporated. It would start in 2027, filed by Tier 2 advice letter, with each CAVA and General Rate Case required to show how engagement and adaptive-capacity findings shaped proposed investments. Energy Division also proposes eight criteria for community adaptive-capacity methods grouped under public interest, transparency, and data resolution — analyses must be understandable to communities and investment decision-makers, ground-truthed against local experience, built on auditable and stable data, comparable across time and geography, and able to detect small pockets of vulnerability that averages obscure. Staff’s key finding is that first-round engagement and technical analysis ran as parallel tracks with no visible link from community input to vulnerability findings or rate-case spending. The Climate Lexicon Report, built by all four large IOUs from CPUC, IPCC, and UN sources, reached consensus on definitions for exposure, hazards, sensitivity, vulnerability, adaptive capacity, disadvantaged vulnerable communities, resilience, risk, and investment prioritization.
SoCalGas Recovers $54.4M Storage-Integrity Undercollection After a $104.6M (31%) Overrun Stayed Just Under the 35% Advice-Letter Cap
Resolution G-3616 authorizes SoCalGas to recover roughly $54.4 million of undercollected costs in its Storage Integrity Management Program Balancing Account for the 2019–2023 rate case cycle. SoCalGas spent about $437.1 million against $332.4 million authorized — a $104.6 million, 31% overrun driven entirely by capital. Because 31% falls under the 35% cap set in D.19-09-051, SoCalGas could pursue recovery by advice letter rather than a full application.
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Energy Division reviewed recorded costs including invoice samples and found them reasonably incurred; SoCalGas attributed the overrun to field assessments revealing more well remediation and abandonment work than forecast, and to a post-test-year forecasting mechanism too coarse for program specifics. The resolution directs a Tier 1 advice letter within 30 days to amortize the $54.4 million plus interest into gas transportation rates over 12 months using the Equal Percent of Authorized Margin method; SoCalGas’s underlying advice letter projects a 0.8% noncore increase, 1.2% core increase, and no BTS rate effect. This is the final SIMP recovery from the two-way balancing account: D.24-12-074 converted SIMP to a one-way balancing account and requires future undercollections to sit in a memorandum account, shifting timing and reasonableness risk to the utility.
CPUC Accepts a Nine-Month Delay for 750 MW of PG&E-Contracted Solar Plus 450 MW of Storage — First Delivery Slips to Sept 1, 2028
Resolution E-5470 approves PG&E amendments to two power purchase agreements with Atlas Solar XII and XIII for projects in La Paz, Arizona. Each remains a 375 MW solar facility paired with 225 MW of lithium-ion storage on a 15-year term, but expected initial delivery slips from December 1, 2027 to September 1, 2028 because of network-upgrade delays.
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The resolution finds the amendments do not change capacity, contract term, RPS product, or pricing, and remain consistent with PG&E’s mid-term reliability, IRP, and RPS procurement obligations. Energy Division found them reasonable on valuation and cost recovery, with costs and benefits flowing through PG&E’s Portfolio Allocation Balancing Account subject to prudent contract administration. Project owner Lydian Energy supported the amendments, noting the delay is under a year and the projects still deliver carbon-free dispatchable capacity at stable long-term pricing. The approval follows the alternative-compliance framework for delayed mid-term reliability procurement in D.25-09-007 and does not constitute final approval to count the projects toward a particular procurement requirement.
Risk Framework Rulemaking Split Into Three Tracks — Benefit-Cost Methodology Reopened, With a Question Whether a BCR of at Least 1.0 Should Gate Investment
Commissioner Harada’s scoping memo divides the Commission’s risk-based decision-making rulemaking into three tracks. Track 1 asks whether the Rate Case Plan should give the Safety Policy Division more time to evaluate RAMP applications; Track 2 reopens the benefit-cost ratio methodology adopted in R.20-07-013; Track 3 addresses whether to adopt a risk-tolerance standard. Track 1 comments were due October 23 and November 6.
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Track 2 will consider whether all utilities should use a single BCR method, whether O&M avoided by an investment belongs in the numerator as a benefit or the denominator as a cost reduction, whether the cost horizon should run four years or the asset’s life, and whether a BCR of at least 1.0 should be required before a utility invests. PG&E must file a summary report and workpaper on its Present Value Revenue Requirement multiplier by February 1, 2027 — the same day a staff proposal on O&M treatment is due. Track 3 asks whether to adopt a risk-tolerance standard or a more flexible framework, whether to confine it to catastrophic risks, and whether affordability should figure in the outcome; utilities filed a joint survey by July 31 and Safety Policy Division’s proposal is due November 16. The OIR was served on A.26-02-005, in which PG&E, SCE, and SDG&E seek approval of a BCR calculation methodology, an audit methodology, and cost-recovery conditions under Res. SPD-37 — so the Commission is considering the subject in two places at once.
Rule 21 — ALJ Orders Cost and Workload Data to Replace the Flat $800 Interconnection Application Fee With a Tiered Structure
An ALJ ruling directs PG&E, SCE, and SDG&E to produce the cost and workload records needed to replace Rule 21’s flat $800 interconnection application fee. The Commission believes the flat fee overcharges simple projects, undercharges complex ones, and may not match utilities’ aggregate processing costs. The ruling also tests the $150 hourly engineering rate carried in the Rule 21 tariff against actual utility engineering costs.
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For applications outside the NEM family, each utility must estimate administrative and engineering hours per review, convert them to fully loaded costs, and report amounts over- or under-collected per application and across all applications received last year. Utilities must also explain how they track staff time, which steps are automated, how many applications clear initial technical screens, and what conditions trigger a detailed study. Remaining prompts explore whether a fee could vary by capacity, technology, export status, and customer class — comparing non-exporting against limited-exporting reviews, standalone solar against co-located solar-plus-storage, and residential against commercial. Appendix A consolidates this into a template covering 2024 and 2025 combined, sorted into five capacity bands from under 30 kW to 5 MW and larger, with each cell calling for applications received, withdrawn, and pending, staff hours, actual review cost, and aggregate capacity; Power Control Systems is named as a candidate cost driver. The ruling accepts estimates where cost accounting or time records do not exist.
Sempra TY 2028 Rate Cases Draw 11 Protests — SoCalGas’s $5.1B Ask Runs ~34% Above 2024, the Last Rates the Commission Actually Set
SoCalGas and SDG&E’s Test Year 2028 rate cases drew 11 protests and six responses on July 20. SoCalGas seeks $5.1 billion for 2028, up $485 million (10.5%) over expected 2027 collections; SDG&E seeks $3.8 billion, up 8.1%. Measured against 2024, SoCalGas’s request runs about 34% higher and SDG&E’s about 41%. TURN cites possible noncompliance with the Commission’s March 2026 RAMP ruling and AB 1167 limits on ratepayer-funded lobbying and advertising.
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The Southern California Generation Coalition says O&M across gas engineering, transmission, and storage would climb about 21% between 2025 and the 2028 forecast, and opposes automatic annual increases for 2029–2031 (6.19%, 5.77%, 5.49%) set by outside cost indexes rather than shown need. The Indicated Shippers target two safety programs that cost more than they save — a $1.25 billion pipe-replacement effort called DREAMS, which clears a benefit-cost test only under a discount rate favoring long-term social benefits, and $84 million for meter protection returning about a penny per dollar spent — and want the earnings-sharing plan stripped out. TURN and Protect Our Communities Foundation both say Sempra has not supplied the forecast-versus-recorded-cost comparisons and actual-return data that AB 2666 and the last GRC require. PCF also attacks SDG&E’s 8.7% 2029 increase, a $232 million undergrounding exception, and a $1.19 billion grid-hardening program; Mussey Grade Road Alliance disputes SDG&E’s risk-scaling function; San Diego Community Power and Clean Energy Alliance warn that moving generation expense into distribution would make CCA customers subsidize bundled service; CEJA questions 70-year pipeline lives justified on a three-year meter forecast.
Cal Advocates Moves to Fold SoCalGas’s $3.76B AMI Project, SDG&E’s $825M Smart Meter 2.0, and the $348.1M SAP Migration Into the GRC — a Combined ~$10B Case
Cal Advocates asked the Commission to consolidate three separate proceedings into the Sempra utilities’ TY 2028 General Rate Case: SoCalGas’s $3.76 billion advanced-metering project, SDG&E’s $825 million Smart Meter 2.0 proposal, and the $348.1 million SAP software migration. It argues metering, billing, and core software are basic utility functions belonging in the budget review, and that one combined case would show customers the full bill rather than splitting it across four dockets.
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If granted, the Commission would judge SoCalGas’s request against a combined bill of nearly $10 billion instead of the $5.1 billion GRC alone, and would decide how much aging pipe and new technology customers can fund at once as gas demand falls. The motion was filed alongside the July 20 protest round and reframes the central question of the case — whether SoCalGas uses forecasts and recovery tools to treat growth as the default even as its customer base shrinks. AB 2666 supports the intervenors by requiring the Commission to compare prior forecasts with recorded costs and adjust the next revenue requirement before approving new rates.
SoCalGas Seeks a 14.8% Backbone Transportation Rate Increase — the Largest of Any Class — Against a 6.2% System Average
SoCalGas’s TY 2028 rate case would raise the average non-CARE residential bill by about $5.67 (7.7%) per month at 35 therms, effective January 1, 2028. By class: core commercial and industrial +6.3%, noncore commercial and industrial +3.7%, electric generators +2.5%, backbone transportation service +14.8%, and wholesale −0.2%, against a 6.2% system average. Beyond 2028 it proposes further increases of $315M (2029), $312M (2030), and $314M (2031).
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The request would fund pipeline inspection, repair, and replacement, integrity work on high-pressure lines, leak abatement, compressor-station modernization, replacement of aging technology, cybersecurity, and customer-service systems. SoCalGas identifies insurance as a significant cost driver, citing higher liability costs and additional wildfire coverage needed after the 2025 Los Angeles fires, and estimates consolidating field processes would avoid about $9.5 million in annual labor costs. On the backbone increase, revenue assigned to the combined BTS and unbundled storage category rises $131 million or 14.4% while the BTS rate rises 14.8%, using allocation results and sales volumes adopted in the 2024 cost-allocation proceeding for both the 2027 and 2028 illustrations — so the increase does not stem from a shrinking billing denominator, and the testimony does not explain why it is so large. Exhibit SCG-05 forecasts gas transmission and storage capital rising 34%, from $384.5 million in 2027 to $515.2 million in 2028.
Phase 3B Reopened to Weigh a Tribal-Lands Exemption From the End of Electric Line-Extension Subsidies — Morongo Cites an ~$80,000 Unsubsidized Cost
A July 23 amended scoping memo reopens Phase 3B of the Building Decarbonization rulemaking to consider whether Tribal lands should be exempt from the elimination of electric line-extension subsidies for mixed-fuel new construction. The memo grants no exemption but adds the question after the Morongo Band of Mission Indians argued the policy imposes disproportionate costs — one member faces an unsubsidized cost near $80,000. Comments were due August 14, 2026.
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D.23-12-037, modified 18 months later by D.25-06-034, cut allowances, refunds, and discounts for extensions to new buildings using gas or propane alongside electricity, effective July 1, 2024. Morongo asked the Commission to preserve subsidies for certified Reservation homes serving Tribal members, residents, or housing programs, plus essential community facilities and small member-owned businesses, arguing Reservation development differs from ordinary subdivisions because federal allotment policy split parcels among many heirs, homes go up individually on scattered sites, and distribution infrastructure is limited. The Tribe argues removing the subsidy will not push residents toward all-electric construction because those homes cost more and the Reservation experiences frequent shutoffs and wind-related outages. Question 1 asks whether an exemption should apply to every electric IOU rather than SCE alone, which would extend relief into PG&E and SDG&E territory. Note this concerns electric line-extension subsidies — distinct from the separate SoCalGas and PG&E gas-line extension allowance applications.
High DER — PD Would Cut ICA Workshops to Twice a Year From 2027 and Require Biennial Grid Modernization Progress Reports Every Even Year
Commissioner Houck’s proposed decision would reduce Integration Capacity Analysis workshops from quarterly to twice yearly beginning Q1 2027, cancelling the Q4 2026 workshop and aligning future sessions with the utilities’ twice-yearly ICA reports. It would also require PG&E, SCE, and SDG&E to serve Grid Modernization Progress Reports on Energy Division by October 1 of every even-numbered year, starting 2026, replacing one-off data requests. Comments were due August 17; earliest consideration September 3, 2026.
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Utilities could seek further schedule changes through Tier 2 advice letters, but would have to show the workload is unduly burdensome or that the status of ICA improvements does not support twice-yearly updates. The progress reports would support the Commission’s biennial grid-modernization report to the Legislature and governor, covering grid-management systems, communications and cybersecurity infrastructure, engineering and planning tools, advanced metering and grid-edge applications — reporting project status, milestones, benefits, use cases, challenges, changes from earlier plans, and costs incurred and anticipated. SDG&E opposed the reporting requirement, arguing the existing data-request process suffices; PG&E and SCE preferred to rely on grid-modernization reports in their general rate cases, and both objected that cost information would duplicate GRC reporting, with SCE also seeking to limit duplicative cost reporting for advanced-metering investments.
PG&E - DAC Community Renewable Energy Tariff Adopted (3-1; Houck Dissent) Following EPA Solar-for-All Termination
The CPUC adopted, by a 3–1 vote (Houck dissenting; Baker recused), a decision in A.22-05-022 implementing the California Shared Renewables Portfolio as a Community Renewable Energy tariff built on the Renewable Market Adjusting Tariff (ReMAT). The IOUs must file Tier 2 advice letters within 90 days; compensation cannot exceed PURPA avoided costs; nonparticipating customers will not fund adders. DAC-GT funding shifts from GHG allowance proceeds to the Public Purpose Program surcharge effective July 1, 2026.
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A
$33 million state appropriation reverted to the General Fund in June 2025; the EPA terminated California's
Solar for All award in August 2025, leaving the program structurally without third-party funding. The decision proceeds anyway by tying the new Community Renewable Energy tariff to ReMAT, rejecting proposals for capacity adders, expanded project sizes, time-of-delivery adjustments, and above-avoided-cost compensation as inconsistent with the Public Utilities Code.
President Reynolds framed the structure as ratepayer-protective: ReMAT permits 20-year contracts vs. 12 years under the PURPA standard offer.
Commissioner Houck dissented, arguing that ReMAT-based compensation may not, in her view, make community-solar projects financeable absent external funding or legislative action. The decision also consolidates Green Tariff oversight into procurement review and ERRA cost proceedings, eliminates annual forums and advisory boards, moves stranded Green Tariff costs into ERRA, and reduces the advice-letter tier required for new CCA
DAC-GT programs from Tier 3 to Tier 2. If no developer executes a
ReMAT PPA within two years of the Tier 2 disposal date, the structure sunsets.
A.24-08-004
Decision Adopted Jun 11, 2026
Decision · Denied
PG&E - Capital Structure Adjustment DENIED (Adopted)
The CPUC adopted the Proposed Decision on Jun 11, 2026, formally denying PG&E’s request to exclude approximately $2.6 billion in wildfire liabilities and state-backed loan amounts from its capital-structure equity ratio. A material ratepayer win that preserves the integrity of the authorized debt-to-equity ratio for purposes of Cost of Capital and downstream customer rates.
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PG&E sought to exclude debt and equity impacts tied to (a) the 2019 Kincade Fire, (b) the 2021 Dixie Fire, and (c) a $1.4 billion forgivable DWR loan tied to the Diablo Canyon extension. The PD rejects PG&E’s request on three separate grounds: the wildfire costs amount to only 0.6% of equity, well below the rule’s 1% adverse-financial-event threshold; the PD refuses to aggregate the Kincade and Dixie events (unrelated incidents years apart) to manufacture a qualifying reduction; and the DWR loan fails independently because a forgivable loan is not an adverse financial event. PG&E’s 2020 waiver covered $8.9 billion in wildfire costs - an order of magnitude larger - and SCE’s approved request would have represented approximately 10% of equity. Neither offers persuasive precedent here.
The most consequential implication sits in the affordability section. The ALJ declines to accept PG&E’s carrying-cost argument at face value and instead credits the ratepayer-protection critique: that operating with debt excluded from capital structure calculations allows PG&E to compensate shareholders based on an inflated authorized equity ratio while ratepayers absorb the leverage risk. The intervenor record shows PG&E’s actual equity has run 7 to 10 percentage points below its authorized 52% since 2021, producing an estimated $2.4 billion in shareholder profits from ratepayers. That theory is now on record and likely travels into Cost of Capital proceedings, wildfire financing debates, and affordability dockets. Comments due June 10. Earliest CPUC consideration: July 2, 2026.
CPUC - Energization Reports Reviewed: Guidehouse Roadmap Sets Revised Reporting Requirements
An ALJ ruling in R.24-01-018 directs PG&E, SCE, and SDG&E to respond to questions arising from Guidehouse's review of the utilities' September 2025 Biannual Energization Reports. Guidehouse found the data insufficient to assess utility compliance with the targets set in D.24-09-020; approximately one-third of required data fields were missing for more than 75% of projects across all three IOUs.
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Why the data failed. D.24-09-020 established enforceable energization targets, an eight-step framework, and a twice-yearly reporting obligation covering tariff projects under Rules 15, 16, 29, and 45, plus main panel upgrades. The September 2025 reports cover projects with complete applications from January 31, 2023 through June 30, 2025 - a window that straddles the decision's September 2024 issuance date.
Each utility's tracking systems failed in a distinct way:
PG&E is still integrating systems and cannot reliably track Step 6 (IOU Site Readiness) or Step 8 (Energization); only 6.3% and 47% of completed tariff projects have start or end dates for those steps. SCE provided complete step-date data across all eight steps (the only utility to do so) but cannot separate IOU-controlled time from customer or third-party time. SDG&E struggled with multiple steps and could not track utility-controlled time separately.
Guidehouse's sufficiency thresholds: 95% availability for compliance data points; 75% for contextual data points. None met those thresholds. The ruling asks parties whether utilities that fail the proposed sufficiency thresholds should be required to file additional reporting on their energization backlogs - effectively converting bad data into its own regulatory problem. Whichever parties shape the definitions of utility-controlled time, customer delay, upstream capacity triggers, actual project costs, and outliers will shape how future energization performance is judged.
CPUC - Resource Adequacy Reform PD: UCAP Framework, 2027-2029 LCRs, 2027 Flex RA
A Proposed Decision adopts the Unforced Capacity (UCAP) framework for the 2028 RA year, sets 2027-2029 Local Capacity Requirements, adopts 2027 Flexible Capacity requirements, modifies storage penalty structures, sets Effective Output limits, and formally ends paper capacity. Comments due June 22, 2026. Earliest Commission consideration: July 2, 2026.
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The PD adopts CAISO's recommended Local Capacity Requirements: 23,618 MW for 2027; 24,545 MW for 2028; and 25,480 MW for 2029. The LA Basin climbs from 6,823 MW to 7,721 MW over the three years; seven of 10 local areas carry the CAISO's resource-deficiency notation. Effective for the 2028 RA compliance year, dispatchable thermal, nuclear, geothermal, and non-hybrid storage resources will have accreditation reduced by their Equivalent Forced Outage Rate during RA Measurement Hours: UCAP = (1 - EFORd) x Pmax, applied separately for summer and non-summer seasons using the best three of the prior four calendar years of CAISO outage data. New resources receive class-average EFORd values until unit-specific history accumulates; thermal generators get NOAA 30-year typical weather-year derates. Preliminary UCAP values publish early 2027; final values September 2027.
Long-Duration Energy Storage is defined as any storage capable of discharging at maximum capacity for at least 8 continuous hours. For 2027, LSEs may count LDES capacity across the full 24-hour Slice-of-Day period using a Forward Charge Period multiplier ranging from 2x (eight-hour resources) to 8x (72-hour-plus resources). Closed-loop pumped storage hydropower receives LDES treatment; open-loop PSH deferred.
Storage charging sufficiency penalty: beginning 2027, an LSE with a MWh charging sufficiency shortfall has that shortfall converted to a flat 24-hour MW adder, applied to each hourly position, with the largest resulting hourly deficiency determining the RA penalty. Energy-only resources may not count toward RA capacity requirements; same-Point of Interconnection rule from 2027 allows EO excess to count toward charging sufficiency at deliverable storage co-located at the same POI, after subtracting the paired storage's own energy sufficiency need.
Rejections: hourly load obligation trading rejected (Energy Division's Transactability Report found no demonstrated inability for LSEs to meet Slice-of-Day obligations under existing mechanisms). The Commission ends paper capacity. Six implementation questions deferred to Track 2: hybrid resource methodology; Must-Offer Obligation basis; EFORd for storage energy component; fifth-hour foldback; Flexible RA interaction; Slice-of-Day template integration. None of those open items will delay the 2028 effective date, but they remain unsettled roughly 15 months before the first UCAP compliance year opens. The mechanics bear unevenly on parties: the charging-sufficiency penalty and the UCAP derating move 2028 accreditation off nameplate capacity for storage and dispatchable thermal, while ending paper capacity tightens real-time deliverability for load-serving entities and the Forward Charge Period multiplier gives long-duration storage a formal accreditation pathway. Opening comments closed Jun 22, 2026; reply comments followed ahead of the Jul 2 vote.
SoCalGas - Safety Culture Plan Adopted; Shareholder-Funded Cost Structure
The CPUC adopted SoCalGas's revised Safety Culture Improvement Plan in I.19-06-014, with the explicit ordering that SoCalGas shareholders, not ratepayers, fund the safety culture fixes. The decision closes the safety culture phase of the long-running Aliso Canyon investigation and establishes a no-ratepayer-cost-recovery rule for plan compliance work.
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I.19-06-014 is the OII opened after the 2015 Aliso Canyon leak and the cascading findings on SoCalGas's institutional safety practices. The decision approves the revised plan as a foundation for implementation, while expressly declining to find that any specific intervention is adequate or effective. SoCalGas must, in its next quarterly compliance report: integrate security into its definition of comprehensive safety; strengthen contractor integration with metrics and oversight comparable to employee-focused efforts; expand its corrective-action program to capture public and non-occupational safety concerns; and demonstrate that "Learning Team" sessions on resource allocation continue until no new insights emerge. The decision also creates a Tier 2 Advice Letter pathway delegating Safety Policy Division authority to approve Safety Culture Improvement Plan revisions when interventions fall short, bypassing a full Commission vote. The decision finds Sempra's participation minimal; SoCalGas must maintain a consolidated plan tracking Sempra contributions and demonstrate through quarterly reporting how parent-level governance responds to assessment findings originally directed at Sempra. CPUC staff retains authority to engage SoCalGas's board directly.
Dais discussion (Jun 11): Commissioner Houck framed approval as a starting point, not an endpoint, with quarterly compliance reports until the next safety culture assessment (no later than August 2029). Commissioner Douglas said safety culture improvement must be demonstrated through measurable outcomes. Commissioner Harada drew on her aerospace background, distinguishing real safety from polished reports and dashboards. President Reynolds emphasized implementation must show measurable outcomes over time.
Cost recovery is the decision's most consequential outcome. SoCalGas has already incurred more than $5 million in unrecoverable Safety Culture Improvement Plan costs; the CPUC again rejects ratepayer recovery for safety culture remediation through the next assessment cycle. Expect Sempra investor disclosures to flag the decision as a 2026 charge against equity.
PG&E - 250 MW Google San Jose Data Center: BARC Refund Cap, Extended Refund Window, Rule 30 Conformance
Draft Resolution E-5455 would let PG&E energize Google's 250 MW San Jose data center while capping annual refunds at actual net revenues (not projected future revenues) and extending the refund window from 10 to 15 years. The agreement must conform to the Rule 30 network-upgrade cost framework within 60 days of that decision. Earliest CPUC vote: July 2, 2026.
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Google's load depends directly on the
Newark-NRS 230 kV line (a $1 billion-plus project whose FERC-approved revenue requirement reaches ratepayers at roughly
$100 million per year) plus more than ten other South Bay transmission upgrades. The CPUC previously capped refunds at
75% of net revenues for the STACK Infrastructure and Microsoft data centers (Resolutions E-5420 and E-5439); here it allows
100%, but only because the
Rule 30 proceeding handles network-upgrade cost exposure separately. Energy Division notes that the
Base Annual Revenue Calculation (BARC) process - built for distribution-scale energization where many similar customers statistically absorb stranded-cost risk - can, unadjusted, refund a large-load customer up to nine times first-year net revenues. The draft therefore caps refunds at actual net revenues and ties final terms to Rule 30. This is the first major California utility–data center supply agreement to clear CPUC staff review under the post-2024 large-load framework and will be cited in every subsequent large-load AL from PG&E, SCE, and SDG&E.
SDG&E - $267.9M Utility-Owned 119 MW Westside Canal 2A Battery Approved Despite 2034 Deliverability Gap
The CPUC approved SDG&E's acquisition of the 119 MW Westside Canal Phase 2a lithium-ion battery (Imperial Valley) from an RWE subsidiary for $267.9 million, plus a 10-year operations-and-maintenance agreement, recoverable through the Cost Allocation Mechanism (CAM). Commissioners approved 5–0 over protests from IEP, CalCCA, and Cal Advocates.
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The project came online in December 2024 and already dispatches in CAISO markets, where RWE sells short-term resource adequacy on a merchant basis, so SDG&E's purchase adds no new physical capacity. Resolution E-5467 finds the project incremental on a technicality (it is not on the baseline resource list) and authorizes full CAM cost recovery. Energy Division reads the 120–220 MW Effective Planning Reserve Margin range as a floor utilities may exceed, rejecting CalCCA's argument that only ~11.4 MW should flow to CAM. The core ratepayer risk is deliverability: the project has interim status for 2025–2026 but will not reach Full Capacity Deliverability Status until transmission upgrades complete, potentially in 2034.
Dais discussion (Jun 11): Commissioner Baker called it the weakest of three utility-owned battery projects before the Commission, citing four reservations - SDG&E's incremental EPRM need may be only about 11 MW; SDG&E is long on Resource Adequacy; the battery likely would remain in service under RWE; and full deliverability remains unresolved until 2034 absent operational changes such as an eight-hour configuration. He nevertheless supported it, saying he would be nervous letting the opportunity pass. President Reynolds emphasized the multi-year review process, independent evaluator oversight, and Energy Division's cost review against comparable projects, framing planning reserve margins as an insurance policy. Mitigation rests on price concessions, RWE penalty provisions, continued CAISO participation, and quarterly CAM Procurement Review Group reporting rather than a firm RA-value guarantee.
CPUC - ReMAT 2026 Price Update: Baseload Jumps 21% to $92.33/MWh
Resolution E-5457 updates fixed avoided-cost prices for the Renewable Market Adjusting Tariff (the feed-in tariff for renewable generators of 3 MW or less). The 2026 prices are $58.38/MWh non-peaking, $67.40/MWh peaking, and $92.33/MWh baseload. PG&E, SCE, and SDG&E must file Tier 1 advice letters within 30 days; existing contracts are unaffected.
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Prices reflect weighted-average Renewable Portfolio Standard contract prices from utility, CCA, and ESP contracts executed 2020–2025 for projects of 20 MW or less. The baseload rate jumps 21% from $75.96/MWh, driven by geothermal contracts dominating the baseload reference set; non-peaking rises from $52.85/MWh; peaking is essentially unchanged from $67.99/MWh. The ReMAT program has produced 65 contracts totaling roughly 112 MW since inception, mostly small hydro and solar PV, with only two contracts executed in 2025. The resolution changes nothing about program design - it is the administratively set avoided-cost rate catching up to a higher-cost environment for small baseload renewables.
CPUC - 2026 Core Transport Agent Fees Reaffirmed; Complaints Up 75%
Resolution G-3621 keeps the $5,000 base fee for all 39 registered Core Transport Agents (non-utility gas suppliers) while assigning variable fees only to CTAs that generated consumer-protection costs in 2025. Consumer Affairs Branch CTA complaints rose 75% to 2,942 in 2025. The largest assessments fall on Wave Energy (~$206,000), SFE Energy (>$118,000), Big Tree Energy, and United Energy Trading/Callective.
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The methodology from Resolution G-3597 remains intact: fixed administrative costs ($212,491, or $5,449 per CTA, within the 20% tolerance band) are spread across all 39 registered agents, while variable costs are assigned by complaint and unauthorized-enrollment activity. The 2026 charges are $5.94 per phone contact and $189.52 per informal written complaint, with $680.43 per unauthorized-enrollment complaint and $739.17 per enforcement action. Unauthorized-enrollment complaints rose nearly 88%, even as total enforcement actions fell 83% (393 in 2024 to 65 in 2025). Four suppliers generated 52% of all complaints, so the cost-causation design leaves high-complaint CTAs paying substantially more than clean-record operators such as BP Energy, Shell, and Calpine, which pay only the $5,000 floor.
CPUC - 2028 LOLE Study Inputs & Assumptions Set (Resource Adequacy)
An Energy Division ruling attaches the Revised Inputs & Assumptions for the 2028 Loss-of-Load-Expectation (LOLE) study. It deploys SERVM 10.28, expands the weather and hydro record to 2000–2024, and moves California demand to the CEC 2025 IEPR forecast. The 2028 CAISO baseline grows nearly 17 GW to 114,813 MW (batteries +9,891 MW, solar +5,555 MW). The LOLE study is expected by August 2026.
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SERVM tests whether CAISO meets the 0.1 days/year LOLE standard. The baseline expansion makes over-reliability a plausible starting point, raising the stakes of staff's stress-test choices (adding perfect demand, reducing capacity pro rata, or lowering the import limit). The load assumptions remain contested: SERVM's modeled 2028 managed peak of 49,388 MW sits 1,032 MW above the IEPR projection because staff calibrate to consumption rather than managed demand. Diablo Canyon is counted in the 2028 RA baseline but excluded from IRP modeling, a mismatch that any RA determination premised on its presence will need to revisit. This ruling sets the assumptions that will produce the first major reliability determination in the proceeding.
CPUC - Risk-Based Decision-Making Framework: Affordability’s Role in Risk-Tolerance Definition Under Review
Parties filed opening comments in the successor to R.20-07-013 (final decision D.25-08-032). The framework governs how utilities quantify and propose safety spending in General Rate Cases. The central dispute: whether the definition of risk tolerance should incorporate affordability. SoCalGas/SDG&E say no; Cal Advocates, ratepayer-advocate parties, Mussey Grade Road Alliance, and EPUC/Indicated Shippers support incorporating ratepayer cost.
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The proceeding picks up unfinished tasks from D.25-08-032: adopting a formal risk tolerance standard, formalizing added RAMP review time for the Safety Policy Division, and standardizing Benefit-Cost Ratio methodology. Ratepayer-advocate parties remain the most skeptical that an abstract standard can be built at all, warning that utilities will drive stated tolerance toward zero because capital grows rate base and profit; that position invokes Arrow's Impossibility Theorem against any representative-consensus working group and favors building on D.25-08-032's budget-constrained portfolios anchored in ESJ affordability. PG&E wants the standard built through evidentiary hearings; SCE wants Benefit-Cost Ratio methodology stabilized first. The key test across parties is unscaled, risk-neutral Benefit-Cost Ratio reporting: a mitigation that clears 1.0 only after risk-aversion adjustments is not the same as one that clears 1.0 before utility scaling.
CPUC - IOU Joint Vehicle-Grid Integration Report: Commercial Bidirectional Pilots Strong, Residential V2X Lags
A joint SCE, SDG&E, and PG&E report filed in R.23-12-008 records the CPUC's third annual Vehicle-Grid Integration Forum (March 25, 2026). Managed and bidirectional charging can reduce long-term distribution costs only through grid-aware coordination across bulk and distribution needs. Passive TOU-driven charging just moves load into new system peaks.
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Vehicle-to-Grid commercial track record has promising data: Tellus Green Power's school-bus deployment ran 74 bidirectional chargers at 98%+ uptime over two years. Residential is a different story: PG&E's Vehicle-to-Everything pilots are behind enrollment targets, held back by equipment costs, customer-side integration complexity, and rate-design constraints. The record now shows the familiar California sequence: large theoretical avoided-cost value, thin customer uptake, rate design that can't target distribution-level constraints, uncertain export compensation, and pilots expiring before they generate scalable rules. The unresolved question is whether VGI can convert from pilot to scaled program before transportation electrification adds incremental peak load that the distribution system cannot absorb without bidirectional flexibility.
A.25-04-001 · PG&E parallel
Settlement May 27, 2026
Settlement Filed
PG&E - 2024 ERRA Compliance: Joint Settlement Resolves All Disputes (No Disallowances)
PG&E, Cal Advocates, and the California Community Choice Association (CalCCA) filed a joint motion seeking CPUC approval of a settlement resolving all disputed issues in PG&E’s 2024 ERRA compliance proceeding. The settlement contains no disallowances, no prudency findings, and no accounting revisions.
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The 2024 ERRA compliance proceeding reviewed PG&E’s utility-owned generation operations, fuel procurement, Resource Adequacy accounting, portfolio balancing entries, and contract administration. Both Cal Advocates and CalCCA initially protested portions of PG&E’s application; both now support approval subject to settlement terms.
Four substantive disputes resolved:
1. Humboldt Bay Unit 3 exhaust valve failure - Cal Advocates withdrew its demand for an outside metallurgical review after PG&E confirmed the failed valve had been recycled. In its place, PG&E agreed to hire an outside consultant for root-cause analysis if a repeat exhaust valve failure causes another forced outage.
2. Balancing account scope - PG&E agreed to include four accounts in future ERRA compliance reviews: New System Generation Balancing Account, Modified Transition Cost Balancing Account, Tree Mortality Non-Bypassable Charge Balancing Account, and BioMat Non-Bypassable Charge Balancing Account.
3. Resource Adequacy - CalCCA accepts that PG&E reasonably calculated retained RA using final derated capacity values for monthly compliance filings; no revision to 2024 accounting needed.
4. PCIA customer vintaging - CalCCA accepts PG&E’s supplemental testimony on customers who opt out of CCA service, opt back in, and relocate within the same CCA territory. Of 156 customers meeting those criteria, PG&E identified one improperly vintaged customer; attributed to human error rather than a system logic defect.
Takeaway. After more than a year of testimony, supplemental testimony, and reopened discovery, Cal Advocates and CalCCA arrive at procedural refinements rather than financial consequences. The most substantive forward-looking change is the expansion of ERRA compliance review scope to four additional balancing accounts. For PG&E this is a favorable compliance outcome.
R.20-08-022 · SB 1221
PD issued May 30, 2026
Proposed Decision
CPUC - SB 1221 Neighborhood Decarbonization Pilot Application Process (PD)
Commissioner Karen Douglas issued a Proposed Decision establishing the application process for SB 1221 neighborhood decarbonization pilots. Authorizes gas corporations to seek approval for voluntary projects that replace gas service with zero-emission alternatives and decommission underlying gas infrastructure. Program capped at 30 pilots statewide. Comments due June 18, 2026. Earliest Commission consideration: July 2, 2026.
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This PD is the CPUC’s first attempt to convert SB 1221 from gas-transition policy into a working project pipeline, and it is structured to make conversion
difficult by design. Slot allocation is primarily between PG&E and SoCalGas/SDG&E by 2024 gas demand (7 each per round for the first two rounds), with one slot reserved for Southwest Gas and one for smaller CPUC-regulated gas corporations. Application deadlines are
December 15, 2026; December 15, 2027; and July 1, 2028 if slots remain. (The PD summary states June 1, 2028, conflicting with the ordering paragraph; the discrepancy should be resolved before adoption.)
Each application must demonstrate via net-present-value analysis (using the applicant’s
WACC as the discount rate) that
avoided gas infrastructure costs exceed the zero-emission alternative cost. Four cost-effectiveness tests are required, varying inclusion of non-ratepayer funding and administrative costs; the governing test excludes both. Applications must also document electric infrastructure upgrades, outreach, GHG emissions forecasts using the Avoided Cost Calculator, and cost-recovery proposals. Crucially, the PD imposes a
67% non-binding expression-of-interest threshold before filing and a
67% binding notarized consent threshold after Commission approval but before any building remediation, appliance removal, or implementation spending. Behind-the-meter costs must be
expensed rather than capitalized, meaning utilities cannot earn their authorized rate of return on BTM investments and may propose amortization periods of up to 10 years. The application process (rather than the lower-touch advice-letter process) keeps every pilot subject to full Commission and intervenor scrutiny, which is where cost allocation, bill-impact assumptions, and electric-grid attribution will be contested. Data collection, reporting, evaluation, and shareholder incentive mechanics are all deferred to Track 4. For ratepayer advocates, the key wins in this PD are (a) governing-test exclusion of admin/outreach costs, (b) BTM expensing, and (c) the application process itself. The principal risk is that the high-touch consent and outreach burden filters out exactly the kinds of dense, working-class, multi-family neighborhoods where pilots would most efficiently displace gas spending.
SoCalGas Angeles Link Phase 2A - Cost Recovery Denied
The Commission denied SoCalGas’s Phase 2A cost recovery request for the Angeles Link hydrogen pipeline pre-development work in D.26-04-034. A May 29 ALJ ruling now asks parties in the Phase 1 cost-recovery proceeding whether any portion of Phase 1 costs should be borne by ratepayers and whether the case can be disposed of on cost-recovery grounds alone without reaching jurisdictional questions.
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D.26-04-034 is the decision that effectively ended SoCalGas’s near-term path to ratepayer-funded Angeles Link development. The Commission’s denial of the Phase 2A request (
$266M for continued pre-development) signaled that ratepayers should not bear ongoing development costs absent stronger evidence of project viability and customer benefit. The May 29 ALJ ruling in the Phase 1 cost-recovery proceeding now asks parties (1) whether it is just and reasonable for ratepayers, or a subset of ratepayers, to bear Phase 1 costs and if so when recovery should occur; (2) whether the CPUC must reach jurisdiction over Angeles Link or can dispose of the proceeding on cost-recovery grounds alone; and (3) the remaining schedule including whether evidentiary hearings are necessary. From a ratepayer protection perspective, the favorable framing is that the Phase 2A denial creates a strong precedent for refusing socialization of Phase 1 sunk costs as well, since the Commission’s rationale (insufficient evidence of project viability) applies equally to retroactive recovery of money already spent. The most defensible outcome is shareholder absorption of all Phase 1 costs, with any cost recovery limited strictly to identifiable subsets of customers who would benefit from a hypothetical built project - a class that may not exist on the current record.
CPUC - Biomethane Cost Allocation: EITE Exemptions Reopened
The ALJ issued a second supplemental comment ruling in R.22-12-011, reopening two questions tied to who ultimately bears Renewable Gas Standard above-market costs. Asks parties to reassess prior positions in light of D.26-04-044 (the April 30 RGS decision), and re-examines whether Energy Intensive Trade Exposed noncore customers should have a pathway to exemption if RGS above-market costs are allocated to noncore. Opening comments capped at 10 pages, due June 3, 2026.
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The reopened EITE exemption question is the structural issue. EITE customers (cement, steel, food processing, refineries) argue they will relocate production out of California if forced to bear RGS above-market costs, citing emissions-leakage risk. The principle is sound but the implementation matters: a poorly designed exemption shifts those costs to
core residential and small commercial customers via rebalancing. The CPUC’s prior position was reluctance to extend new exemptions absent demonstrated leakage risk. Now
D.26-04-044 has reshaped the RGS in ways that may alter the cost incidence, and the ALJ is asking parties to revisit their positions. Most defensible ratepayer position: any EITE exemption must (a) be capped at a defined percentage of RGS volume; (b) be conditioned on demonstrable trade-exposure metrics from CARB’s existing cap-and-trade leakage framework, not ad hoc industry self-certification; and (c) include sunset provisions tied to the RGS itself. Without these guardrails, EITE exemptions become a permanent cross-subsidy from residential to industrial customers.
Res. E-5417
Adopted April 30, 2026
Resolution
Liberty Utilities (CalPeco) - Income-Graduated Fixed Charge Implementation
The Commission approved with modifications Liberty Utilities’ advice letters implementing an income-graduated fixed charge (Base Services Charge) for residential customers under D.24-05-028. This is the first IGFC implementation outside the three large IOUs.
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D.24-05-028 authorized IGFCs for PG&E, SCE, and SDG&E pursuant to AB 205. Liberty’s implementation extends the design to a multi-jurisdictional utility and creates the first benchmark for how IGFC mechanics translate outside the three large IOU service territories. Income-verification process improvements remain under deliberation in R.26-04-009 (Advanced Electric Rate Design OIR).
R.22-11-013
Workshop April 29, 2026
Workshop / Comments
CPUC Energy Division - 2026 Avoided Cost Calculator Staff Proposal Workshop
The CPUC Energy Division hosted a workshop on the 2026 Avoided Cost Calculator staff proposal, which underpins cost-effectiveness analysis for distributed energy programs across PG&E, SCE, SDG&E, and SoCalGas. Opening comments are due May 13; reply comments May 18, 2026.
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The Avoided Cost Calculator (ACC) sets the avoided cost benchmarks used in benefit-cost tests for energy efficiency, demand response, distributed generation, and storage. Updates to the ACC propagate through every DER program cost-effectiveness filing. The 2026 update sits at the intersection of the community solar PD (A.22-05-022) and the new rate-design rulemaking (R.26-04-009) and is consequential for net-energy-metering successor program cost-effectiveness as well.
R.20-08-022 · SB 1221
Solicitation open · Statutory deadline July 2026
Pilot Designation
CPUC - SB 1221 Neighborhood-Scale Decarbonization Pilot: Community Solicitation
The CPUC is soliciting communities interested in participating in the SB 1221 neighborhood-scale gas-to-electric switching pilot program. PG&E’s first “zonal electrification” project would electrify approximately 1,200 state university housing units. The Commission has a July 2026 statutory deadline to establish the program.
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SB 1221 requires 67% property owner consent before any pilot may be approved, which is a real constraint on deployment whose mechanics have not been fully designed. Cost-recovery questions (who pays, how stranded gas assets are treated, whether utilities earn on electrification capital) are the substantive issues that will determine whether the program operates as written. The pilot is also the testing ground for distributional outcomes in disadvantaged communities under the Commission's ESJ Action Plan.
R.26-04-001
Opened April 9, 2026
New Rulemaking
CPUC - Large Load / Data Center Electric Rate Design OIR
The CPUC opened a new Order Instituting Rulemaking at its April 9 voting meeting to determine how system upgrade costs driven by surging data center and large-load demand are allocated across ratepayers - addressing whether new large industrial customers pay full infrastructure costs or those costs are socialized across all customer classes.
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California data center electricity demand is projected to grow 40–60% by 2030, requiring billions in new transmission and distribution infrastructure. The core policy question is cost causation: should large-load customers whose demand drives upgrade requirements bear those costs directly, or should they be allocated across all ratepayers through general rate increases?
The proceeding follows a series of CPUC authorizations for merchant transmission lines serving data center load pockets - including the $813M Power the South Bay project and $1.593B Santa Clara Valley project adopted at the March 19, 2026 voting meeting. Those merchant projects were funded by large customers. The new rulemaking will establish a durable framework for cost allocation going forward, with ratepayer advocates and environmental groups expected to weigh in heavily. A decision is anticipated in 2027.
I.26-04-008
Opened Apr 9, 2026
Investigation
CPUC Investigation - PG&E Elkhorn Energy Storage: Prolonged Outage May Trigger Cost Disallowance
The CPUC opened an investigation into whether PG&E's Elkhorn Battery Energy Storage System at Moss Landing has been out of service for nine or more consecutive months - a threshold that triggers potential disallowance of storage costs from regulated rates under CPUC rules.
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The Elkhorn Battery Energy Storage System is a 182.5 MW / 730 MWh lithium-ion storage facility located at the Moss Landing power plant complex in Monterey County - one of the largest grid-scale storage facilities in the world at the time of its commissioning. The facility has been under prolonged outage following fire and safety concerns that have affected the Moss Landing complex since late 2024.
CPUC regulations provide that if a utility-owned or utility-contracted resource remains out of service for nine or more consecutive months, the Commission may disallow expenses associated with that resource from ratepayer recovery - effectively requiring PG&E to absorb costs rather than pass them through to customers. This investigation will determine whether the Elkhorn outage has crossed that threshold and, if so, what costs are subject to disallowance. The proceeding has significant precedent value for how California regulators treat storage facility outages going forward.
R.26-04-009
Opened Apr 9, 2026
Rulemaking
Advanced Electric Rate Design OIR
CPUC opens rulemaking to redesign advanced electric rates for residential and non-residential customers, succeeding R.22-07-005. ALJ Joanna Perez-Green and Commissioner John Reynolds assigned April 22, 2026.
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R.26-04-009 is the CPUC's successor rulemaking to R.22-07-005, which established the current advanced residential rate framework including default time-of-use rates and income-graduated fixed charges. The new OIR expands scope to non-residential customers and addresses rate design for high-electrification scenarios -- how rates should be structured as buildings and transportation shift to electricity. ALJ Joanna Perez-Green and Commissioner John Reynolds were assigned April 22, signaling Commission prioritization. The proceeding will shape how millions of California ratepayers are billed for electricity as the grid transitions and fixed-cost recovery shifts away from volumetric charges.
R.24-01-018
ALJ Ruling Apr 17, 2026
ALJ Ruling
CPUC - Energization Timelines ALJ Ruling: Bridge-Year Enforcement Framework
ALJ Dugowson issues a ruling in R.24-01-018 establishing the procedural framework for CPUC enforcement of electric service energization timelines - addressing how PG&E, SCE, and SDG&E must meet Rule 21 and new service connection deadlines as the Commission develops enforcement tools.
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R.24-01-018 is the CPUC's rulemaking on energization timelines - the time it takes utilities to connect new customers, rooftop solar, and battery storage systems to the grid. Data shows PG&E and SCE meet Rule 21 interconnection timelines as little as 18% of the time, prompting the JLAC to authorize a state audit (JLAC 2026-126) and the CPUC to develop formal enforcement mechanisms.
This April 17 ALJ ruling by ALJ Dugowson sets out the procedural schedule and framework for how the Commission will enforce compliance going forward, including potential penalty mechanisms. The ruling is significant because it marks the CPUC's first formal procedural step toward creating binding enforcement tools for energization delays - a longstanding pain point for solar installers, EV charging developers, and customers awaiting new service connections.
A.24-03-019
Decision Apr 30, 2026
Decision Adopted
SCE 2024 General Rate Case Phase 2 - Rate Design Adopted
CPUC adopts rate design settlements in SCE's 2024 GRC Phase 2, finalizing how revenue authorized in Phase 1 is allocated across rate schedules and customer classes effective with the next rate cycle.
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GRC Phase 2 proceedings set rate design -- the allocation of revenue requirement authorized in Phase 1 across SCE's various customer rate schedules (residential, commercial, industrial, agricultural, EV, etc.). The April 30 decision adopts the negotiated rate design settlements, locking in how SCE will recover its authorized revenue from different customer groups through at least the next general rate case cycle. Rate design outcomes directly affect the distribution of costs between high- and low-usage customers, the structure of tiered vs. flat rates, and the incentive signals embedded in time-of-use and demand charge schedules. The decision follows separate Phase 1 revenue requirement proceedings already concluded.
Res. E-5436
Adopted Apr 30, 2026
Resolution Adopted
California DGStats Platform - Funding Tripled to $2.6M
CPUC adopts Resolution E-5436, tripling the budget for the California Distributed Generation Statistics platform to $2.6 million per 3-year contract with annual inflation adjustment authority. DGStats is the statewide hub for rooftop solar, battery storage, and DER interconnection tracking.
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The California DGStats platform (californiadgstats.ca.gov) aggregates interconnection data from all California IOUs and publishes monthly reports on distributed energy resource deployments -- rooftop solar capacity, battery storage installations, EV chargers, and interconnection queue status by utility and zip code. It is the authoritative public data source used by CPUC staff, researchers, local governments, and industry to track California's DER buildout.
Resolution E-5436 increases the contract budget from approximately $875,000 to $2.6 million per 3-year cycle -- roughly tripling current funding -- and authorizes the Energy Division to adjust annually for inflation. The funding increase reflects the platform's growing role as the backbone for CPUC interconnection planning, enforcement, and ICA (Integration Capacity Analysis) compliance tracking. All three large electric IOUs (PG&E, SCE, SDG&E) contribute data to the platform and fund it through their rates.
A.24-03-009
Adopted April 9, 2026
Adopted
PG&E - Citizens Energy $1B Transmission Lease Approved (§851)
The CPUC adopted the proposed decision authorizing PG&E to lease transmission entitlements to Citizens Energy Corporation under up to five 30-year leases worth up to $1 billion. After-tax profits - estimated at over $450 million over 35 years - will fund bill-payment assistance for low- and moderate-income PG&E customers.
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The Commission adopted the decision authorizing PG&E to lease entitlements on new high-voltage transmission projects to Citizens Energy Corporation - a nonprofit - through up to five 30-year leases. Citizens Energy funds grid upgrades (safety, reliability, capacity) in exchange for the entitlements. The arrangement satisfies Public Utilities Code §851 public interest requirements, per the adopted decision by ALJ Jack Chang.
Total investment up to $1 billion. Citizens Energy commits to directing 50% of net after-tax profits to clean energy for low-income communities in Central and Northern California, rising to 90% over time. Over 35 years, the CPUC estimated after-tax profit flows to low-income customers at over $450 million.
Res. E-5440
Adopted April 9, 2026
Resolution Adopted
ICA Remediation Plans Adopted - PG&E, SCE, SDG&E Ordered to Fix Interconnection Capacity Data
The CPUC adopted Resolution E-5440, directing PG&E, SCE, and SDG&E to correct Integration Capacity Analysis data deficiencies within a specified compliance timeline. Accurate ICA data governs distributed energy resource interconnection across all three service territories.
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The Integration Capacity Analysis (ICA) is a map-based tool showing how much distributed energy resource capacity each grid segment can accommodate without costly upgrades. CPUC staff found that all three large IOUs had methodology errors and data gaps that could mislead rooftop solar, battery storage, and EV charger applicants about available interconnection headroom.
Resolution E-5440, adopted at the April 9, 2026 voting meeting after being held from March 19, requires each utility to submit corrected ICA data and a remediation plan to CPUC staff within a specified timeline. Failure to provide accurate ICA data can cause developers to incur pre-development costs for projects that will ultimately face prohibitive grid upgrade requirements - a longstanding complaint from the California solar and storage industry.
A.24-06-001
Adopted April 9, 2026
Adopted
SDG&E - 2023 ERRA Compliance: $214.6M Net Undercollection Approved for Recovery
The CPUC adopted the proposed decision in A.24-06-001, approving SDG&E's recovery of a net $214.6 million 2023 energy procurement undercollection with modifications to RA portfolio valuation, RPS accounting, and battery storage revenue allocation. Commissioner Christine Harada presided after a March 19 holdover.
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The Energy Resource Recovery Account (ERRA) mechanism allows SDG&E to track and recover reasonable energy procurement costs that differ from the forecast embedded in rates. The 2023 compliance filing reviewed whether procurement was prudent and consistent with the Commission-approved plan. The net $214.580 million undercollection flows back to customers through future rate adjustments.
The adopted decision includes modifications: SDG&E must update its resource adequacy portfolio valuation methodology, correct RPS compliance accounting, allocate battery storage revenues across a broader customer base, and recover Stranded Green Tariff Shared Renewables costs via the Public Purpose Programs charge. The item was held from the March 19 voting meeting to April 9 following reassignment to Commissioner Christine Harada.
A.22-05-022
PD Issued Apr 7, 2026
Proposed Decision
PG&E - Green Tariff Shared Renewables & DA Community Solar Programs PD
ALJ Kao issues a proposed decision implementing PG&E's Green Tariff Shared Renewables, Disadvantaged Communities Green Tariff, and Community Solar Green Tariff programs - establishing program rules, customer enrollment procedures, and cost-recovery mechanisms for this shared clean energy portfolio.
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California's Green Tariff Shared Renewables program allows customers - including renters and others who cannot install rooftop solar - to subscribe to a share of a utility-owned or utility-contracted renewable energy project and receive a credit on their bill. The Disadvantaged Communities Green Tariff extends this model specifically to low-income customers in disadvantaged communities with additional subsidy. The Community Solar Green Tariff involves smaller, community-scale projects with local siting requirements.
This consolidated PD (covering A.22-05-022, A.22-05-023, and A.22-05-024) implements the regulatory framework for all three programs - setting subscription sizes, credit calculation methods, program caps, and cost allocation to non-participating ratepayers. The decision will affect how hundreds of thousands of California customers who want renewable energy access clean power without installing their own systems. Comments are expected in late April 2026.
A.24-03-018
PD Issued Apr 10, 2026
Proposed Decision
PG&E - Diablo Canyon Extended Operations Cost Recovery (Sep 2023 – Dec 2025)
ALJ Atamturk issues a proposed decision granting in part PG&E's petition to modify D.24-12-033, authorizing recovery of extended operation costs incurred at Diablo Canyon from September 2023 through December 2025 and addressing 2025 volumetric performance fees.
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Diablo Canyon Power Plant - California's last operating nuclear facility, with 2,200 MW of carbon-free generation - was extended beyond its original 2025 closure date through state legislation (SB 846, 2022) and a Department of Energy loan to PG&E. The facility's continued operation required significant incremental costs: maintenance, licensing fees, and regulatory compliance from September 2023 onward that were not included in prior rate cases.
This PD addresses PG&E's request to modify D.24-12-033 to authorize recovery of those incremental costs from ratepayers. The Commission previously approved a framework for Diablo Canyon cost recovery; this proceeding resolves the specific amounts for the September 2023 through December 2025 period and sets 2025 performance fee volumes. The decision is significant for California's nuclear policy and for the broader question of how ratepayers bear the cost of facility life extensions driven by state policy decisions. An alternate PD was also filed concurrently, indicating commissioner-level disagreement on scope or methodology.
A.26-01-007
PD Issued Apr 10, 2026
Proposed Decision
SCE - Woolsey Fire Recovery Bond Securitization: Financing Order PD
ALJ DeAngelis issues a proposed decision authorizing SCE to issue rate reduction bonds to securitize its Woolsey Fire wildfire costs under AB 1054 - converting higher-cost traditional rate base recovery into lower-cost bond financing to reduce the total burden on ratepayers.
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AB 1054 (2019) established a wildfire fund and authorized utilities to securitize approved wildfire costs through rate reduction bonds (also called catastrophe bonds or securitization bonds). Securitization replaces traditional utility financing - where the utility borrows at its weighted average cost of capital - with lower-cost bond financing backed by a non-bypassable charge on customer bills. Because bonds carry lower interest rates than utility debt, securitization reduces the total cost of recovery for ratepayers over the repayment period, typically 15–25 years.
SCE's application (A.26-01-007) seeks a financing order authorizing approximately $1.84 billion in rate reduction bonds for approved Woolsey Fire costs. This PD, if adopted, would issue the financing order allowing SCE to go to market with the bonds. The non-bypassable charge on bills provides bondholders security equivalent to a senior utility obligation - enabling the lower financing cost. Comments on the PD are due in late April 2026, with a decision expected at the May or June 2026 voting meeting.
A.24-05-014
Adopted Mar 19, 2026
Adopted (Consent)
LS Power - "Power the South Bay" 230-kV Transmission CPCN Approved - $813M
ALJ Nilgun Atamturk recommends approval; Commission adopts on consent. LS Power is granted a CPCN to construct a 12-mile 230-kV transmission line connecting PG&E's Newark substation to Silicon Valley Power's Northern Receiving Station, with an LS Power cost cap of $813.2 million. In-service target: June 1, 2028.
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A CPUC CPCN is required before a developer can construct new electric transmission facilities in California. The CPCN process reviews need, site suitability, environmental impacts, and consistency with CAISO transmission planning requirements.
The Power the South Bay Project is a 12-mile 230-kV double-circuit transmission line running from PG&E's Newark substation (Alameda County) to Silicon Valley Power's Northern Receiving Station in San Jose. The project addresses transmission constraints in the South Bay load pocket and supports load growth from data centers and electrification. LS Power's cost cap is $813,240,000; the broader project including related PG&E substation work totals approximately $1.59 billion. Construction was authorized to begin March 2026 with a June 1, 2028 in-service deadline. Commissioner Karen Douglas presided; the item passed on the consent agenda.
A.09-09-022
Adopted Mar 19, 2026
Adopted (Consent)
SCE - Alberhill System Project CPCN Approved: $481.7M Transmission
Commission adopts the Alberhill System Project CPCN on consent. SCE is authorized to construct transmission lines and substations in western Riverside County, with a capital cost cap of $481.7 million (2023 dollars, including 15% contingency). In-service target consistent with Inland Empire load growth timeline.
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Originally filed September 2009, the Alberhill System Project is one of the longest-running CPUC transmission proceedings in recent history. The project addresses transmission constraints in the western Riverside County load pocket driven by Inland Empire population growth and electrification load. Years of route modifications, environmental review, and community opposition delayed final CPCN authorization.
The Commission granted the CPCN on the consent agenda at the March 19, 2026 voting meeting - reflecting unanimous staff and ALJ recommendation. Capital cost cap: $481,700,000 (2023 constant dollars), including a 15% contingency of $53.8 million. Costs are recovered through SCE's FERC-regulated transmission rate base - borne by all SCE ratepayers through transmission charges on monthly bills. The proceeding closes upon adoption.
A.24-04-001
PD Released Mar 6, 2026
Proposed Decision
SCE - 2023 Energy Resource Recovery Account (ERRA) Compliance
SCE's 2023 ERRA compliance - PD identifies a $63.2 million decrease in revenue requirement, flowing to customers as a net rate reduction. Comments due March 26, 2026.
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SCE's annual ERRA compliance filing for 2023 - the Commission reviews whether procurement was reasonable and consistent with its approved plan. The ERRA mechanism ensures customers pay only for prudent energy costs; overcollections flow back as rate reductions. Proposed Decision issued by ALJ Jeffrey Lee.
The PD addresses a $63.195 million decrease in revenue requirement across seven accounts - customers receive a net rate reduction reflecting an overcollection in 2023. Comments due March 26, 2026.
R.20-08-020
Court Ruling Mar 9, 2026
Court Upheld
NEM 3.0 - Court of Appeal Upholds D.23-02-015; Challenge Closed
California Court of Appeal upholds NEM 3.0 (D.23-02-015), which reduced solar export compensation for new residential solar customers to ~$0.05–$0.08/kWh - down from ~$0.30/kWh under prior NEM 2.0. Proceeding closed.
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NEM 3.0 (D.23-02-015), adopted April 2023, replaced California's highly compensatory NEM 2.0 tariff for new rooftop solar customers. Under NEM 2.0, utilities credited solar exports at the full retail rate (~$0.30/kWh). Under NEM 3.0's Net Billing Tariff, new customers receive Avoided Cost Calculator-based rates averaging $0.05–$0.08/kWh - an ~80% reduction. Existing NEM 2.0 customers are grandfathered for 20 years.
Solar industry groups and several municipalities challenged the decision in court, arguing the CPUC failed to meet public notice requirements and violated the renewable energy mandate. California's First District Court of Appeal upheld the CPUC's decision on March 9, 2026 - rejecting all procedural and substantive challenges. NEM 3.0 remains binding law; the rooftop solar compensation question is now definitively resolved for the foreseeable future.
I.23-03-008
Adopted Feb 26, 2026
Adopted 4–0 · Closed
Winter 2022–23 Natural Gas Price Spike Investigation - No Misconduct Found
No misconduct found in the winter 2022–23 gas spike; PG&E, SoCalGas, and storage providers exonerated. Core Procurement Charge cap adopted prospectively - triggered when monthly core price exceeds 150% of the 10-year average.
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Opened March 2023 following the winter 2022–23 gas spike - some SoCalGas customers received bills exceeding $400 in January 2023. The Commission investigated whether PG&E, SoCalGas, SDG&E, and independent storage operators engaged in market manipulation, withholding, or imprudent procurement. After nearly three years, the Commission closed the investigation with no finding of misconduct, attributing the spike to coincident demand peaks and pipeline constraints outside California.
No penalties, fines, or refund orders against any utility. Prospective remedy: Core Procurement Charge (CPC) cap triggered when monthly core procurement price exceeds 150% of the 10-year average (November–March window). Undercollections amortized - not borne by shareholders.
A.25-06-012
PD Issued Feb 13, 2026
Proposed Decision
SoCalGas - Gas Cost Incentive Mechanism (GCIM) Year 31 Shareholder Award
SoCalGas earns a $8.374 million shareholder award under GCIM Year 31 - procurement came in $42.1 million below benchmark. $33.77 million flows to ratepayers as lower gas costs.
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The Gas Cost Incentive Mechanism (GCIM) is SoCalGas's procurement performance incentive, in place since the mid-1990s. Each year the CPUC reviews whether SoCalGas beat or missed its benchmark procurement cost. A positive result triggers a shareholder reward; a negative result triggers a shareholder penalty. The mechanism aligns utility incentives with ratepayer interests in keeping gas costs low.
Shareholder reward: $8,374,056 for GCIM Year 31 (2024–2025 gas year). SoCalGas's recorded procurement costs were $42,142,370 below benchmark, of which $33,768,315 flows to ratepayers as lower gas costs and $8,374,056 goes to shareholders. Customers save roughly $4 for every $1 awarded to shareholders.
A.25-06-007
PD Issued Feb 12, 2026
Proposed Decision
SCE - $9.85B Debt & $1.155B Preferred Equity Authorization
SCE authorized up to $9.85 billion in long-term debt and $1.155 billion in preferred equity for capital programs - $525 million below SCE's original $10.375B request.
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Utilities seek CPUC authority to issue debt and equity in advance of actual issuances, allowing them to move quickly when capital market conditions are favorable. This authorization covers SCE's anticipated capital needs driven by its wildfire mitigation capital program (WMCE), infrastructure replacement, and clean energy integration.
Authorized: $9,850,000,000 in long-term debt (SCE requested $10,125,000,000 - reduced by $275,000,000) and $1,155,000,000 in preferred equity (reduced by $250,000,000). Actual issuances within this cap do not require additional CPUC approval. Cost recovery occurs as capital is deployed and included in future GRC proceedings.
A.25-08-008
Adopted Feb 5, 2026
Interim Auth. Adopted
SoCalGas - Distribution Integrity Management Program $35.5M Interim Rate Recovery
D.26-02-006 grants SoCalGas a $35.5 million interim authorization (60% of $59.1M requested) for DIMP costs 2019–2023. 12-month authority; overage refunded with interest if final amount differs.
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The Distribution Integrity Management Program (DIMP) is a federally-mandated natural gas pipeline safety program requiring operators to assess and remediate risks across their distribution systems. SoCalGas operates one of the largest gas distribution networks in North America - approximately 100,000 miles of pipeline serving 21 million customers.
Interim rate authority allows SoCalGas to recover $35,500,000 of the $59,100,000 claimed for DIMP costs incurred 2019–2023 while the full rate case proceeds. The interim amount represents a 60% grant - a common Commission approach to balance utility cash flow needs against unresolved prudency questions. Any amount recovered under the interim authorization that exceeds the final approved amount must be refunded to ratepayers with interest. The 12-month authorization expires in early 2027.
A.22-05-015/016
Voted Jan 15, 2026
Decision
SDG&E / SoCalGas - Wildfire Mitigation Cost Recovery GRC (2019–2022)
SDG&E wildfire mitigation cost recovery: Commission disallows $434.9 million - approving $90.6M of $284M O&M and $945.2M of $1,188M capital requested.
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The Commission rules on SDG&E's wildfire mitigation cost recovery within its consolidated General Rate Case (A.22-05-015/016 with SoCalGas). SDG&E sought recovery of $284 million in wildfire-related operations and maintenance costs and $1,188 million in capital expenditures incurred from May 2019 through December 2022. The Commission approved $90.6 million in O&M (disallowing $192.6M) and $945.2 million in capital (disallowing $242.4M) - a combined disallowance of approximately $434.9 million, signaling heightened scrutiny of wildfire mitigation spending and cost controls. The decision reinforces the Commission's use of cost reasonableness review to protect ratepayers from imprudent utility capital investments.
A.23-04-003
PD Voted Jan 15, 2026
Decision
SCE - ERRA Compliance Review 2022
SCE found compliant with its adopted procurement plan for 2022; $51.4 million in recorded energy procurement costs authorized for recovery.
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The Commission reviews SCE's Energy Resource Recovery Account (ERRA) compliance for the record period January 1 through December 31, 2022. The PD finds that SCE's procurement-related operations - including power purchases, generation dispatch, and greenhouse gas compliance instrument procurement - complied with its adopted procurement plan. SCE's request to recover $51.442 million in costs recorded across five regulatory accounts is authorized. ERRA compliance proceedings are annual filings required of each electric IOU to verify that procurement spending was prudent and consistent with Commission-approved plans before costs are passed through to ratepayers.
Res. E-5437
Adopted Jan 15, 2026
Resolution
PG&E - Dirac 225 MW Battery Storage (Balsam/Aypa Power)
PG&E approved to contract with Balsam Project (Aypa Power) for a 225 MW lithium-ion battery energy storage system, 15-year contract, commercial operation May 2028.
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The Commission approves PG&E's contract with Balsam Project LLC (developed by Aypa Power) for the Dirac Battery Energy Storage System, a 225 MW lithium-ion facility with a commercial operation date of May 20, 2028. The 15-year contract begins August 1, 2028. The procurement supports California's grid reliability and clean energy integration goals - battery storage is critical for absorbing excess solar generation during midday and discharging during evening peak demand periods. Contract costs flow through PG&E's procurement cost recovery mechanisms and are ultimately borne by ratepayers.
Res. E-5396
Adopted Jan 15, 2026
Resolution
PacifiCorp - Income-Graduated Fixed Charge (BSC) Approved
PacifiCorp income-graduated fixed charge (basic service charge) for residential customers approved with modifications per D.24-05-028 AB 205 rate reform framework.
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The Commission approves, with modifications, PacifiCorp's Advice Letters implementing an income-graduated fixed charge (basic service charge) for residential customers, as directed by Decision 24-05-028. The income-graduated fixed charge is part of California's AB 205 rate reform, which restructures electric rates to include a fixed monthly charge scaled to household income - reducing the per-kWh volumetric rate in exchange. PacifiCorp serves a small portion of northeastern California; this approval extends the fixed charge framework beyond the three large IOUs and establishes precedent for the broader statewide rollout.
R.21-03-011
Decision Jan 15, 2026
Decision
Provider of Last Resort (POLR) Guidelines - SB 520
Commission adopts streamlined POLR eligibility guidelines for non-IOU entities under SB 520, opening CCA and other entities to seek full POLR designation.
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The Commission adopts a decision establishing streamlined eligibility guidelines for non-IOU entities seeking Provider of Last Resort (POLR) designation under Senate Bill 520. POLR is the obligation to serve customers who lose their electricity provider - historically this responsibility has fallen to IOUs as default. SB 520 opened the door for community choice aggregators (CCAs) and other entities to apply for POLR status. The adopted guidelines specify application requirements and evidentiary standards. As of this decision, no non-IOU entity has formally sought comprehensive POLR designation, but the framework is now in place for future applicants.
R.18-07-003
Decision Jan 15, 2026
Petition Denied
BioMAT Tariff End-Date Extension - Petition Denied
Petition to extend the Bioenergy Market Adjusting Tariff (BioMAT) beyond its December 2025 end date denied; program closes as scheduled per Governor Newsom's Executive Order N-5-24.
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The Commission denies a petition by the Bioenergy Association of California (BAC) to modify Decision 20-08-043 and extend the Bioenergy Market Adjusting Tariff (BioMAT) program beyond its scheduled end date of December 31, 2025. BioMAT provided feed-in tariff contracts for small bioenergy facilities - including dairy biogas, forest biomass, and landfill gas projects - interconnected to IOU distribution systems at above-market rates. The denial is consistent with Governor Newsom's Executive Order N-5-24, which maintained the BioMAT sunset date. The program's closure shifts bioenergy procurement to other pathways, including the Renewable Gas Standard and bilateral power purchase agreements.
A.24-05-008
PD Released Jan 30, 2026
Proposed Decision
PG&E - Risk Assessment Mitigation Phase (RAMP) Proceeding Close
Proposed Decision to close PG&E's RAMP proceeding - confirms the RAMP record is accepted as informational and incorporated into its General Rate Case.
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The Risk Assessment Mitigation Phase (RAMP) is a CPUC-mandated pre-GRC safety proceeding. Before filing a GRC, each large IOU must conduct a structured safety risk assessment across its assets - using a defined risk model - and file the RAMP report for Commission review. The RAMP record informs the Commission's evaluation of GRC safety spending requests but does not itself set rates.
Closing the RAMP proceeding formally incorporates the RAMP record into the GRC proceeding record and ends the standalone RAMP docket. The adopted RAMP report for PG&E's 2027 GRC cycle was already submitted; this closure is procedural. No direct rate impact - RAMP outcomes influence but do not directly determine approved GRC safety spending levels.
R.19-10-005
PD Released Jan 23, 2026
Proposed Decision
EPIC Phase 4 - Strategic Objectives & Triennial Investment Plan PD
Proposes the Electric Program Investment Charge (EPIC) Phase 4 triennial plan, updating strategic objectives for clean energy technology R&D investment by PG&E, SCE, and SDG&E.
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The Electric Program Investment Charge (EPIC) is a customer-funded clean energy R&D program managed by the California Energy Commission (CEC) and the three large electric IOUs - PG&E, SCE, and SDG&E. Customers pay the EPIC charge (~$130–$170 million per year statewide) to fund applied research, technology demonstrations, and market facilitation for renewable energy, grid integration, and demand response.
Phase 4 covers 2026–2028. The PD updates investment priorities to align with California's evolving clean energy goals - including offshore wind integration, long-duration storage, building electrification, and grid modernization. IOU-administered funds focus on projects with near-term deployment potential in IOU territories; CEC-administered funds cover longer-horizon R&D. The EPIC charge is a small surcharge on all electric bills - ratepayers fund this program indirectly through their electricity rates.
R.10-05-004
PD Released Jan 21, 2026
Proposed Decision
CSI/SGIP - Petition for Modification Denied
Denies a petition to modify the Self-Generation Incentive Program (SGIP) and California Solar Initiative (CSI) incentive structures.
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The Self-Generation Incentive Program (SGIP) provides rebates to customers who install behind-the-meter energy storage, fuel cells, or other clean generation resources. The California Solar Initiative (CSI) funded incentives for rooftop solar installations - its funding is largely exhausted, but the program framework remains in CPUC rulemaking. Petitions for modification (PFMs) allow stakeholders to formally request changes to prior Commission decisions.
This PD denies the petition, maintaining the existing SGIP incentive tiers and CSI framework without modification. The petitioner's proposed changes - not specified in the card - were found insufficient to warrant reopening the rulemaking. SGIP is funded by a surcharge on electric bills for PG&E, SCE, and SDG&E customers; denial of this PFM preserves current incentive structures and budget allocations.
No matches for selected IOU.